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Non-accelerated filer o (Do not check if a smaller reporting company)

Smaller reporting company o

Emerging growth company

10-K 1 cvx12312017-10kdoc.htm 10-K Document

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

þ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2017

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______ to ______

Commission File Number 001-00368

Chevron Corporation

(Exact name of registrant as specified in its charter)



Delaware	94-0890210	6001 Bollinger Canyon Road, San Ramon, California 94583-2324
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)	(Address of principal executive offices) (Zip Code)

Registrant’s telephone number, including area code (925) 842-1000

Securities registered pursuant to Section 12 (b) of the Act:



Title of Each Class		Name of Each Exchange on Which Registered
Common stock, par value $.75 per share		New York Stock Exchange, Inc.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.

Yes þ No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

Yes o No þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o No þ

Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter — $197,705,630,543 (As of June 30, 2017)

Number of Shares of Common Stock outstanding as of February 12, 2018 — 1,910,253,256

DOCUMENTS INCORPORATED BY REFERENCE

(To The Extent Indicated Herein)

Notice of the 2018 Annual Meeting and 2018 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934, in connection with the company’s 2018 Annual Meeting of Stockholders (in Part III)

THIS PAGE INTENTIONALLY LEFT BLANK

TABLE OF CONTENTS



ITEM		PAGE
PART I
1.	Business	3
	General Development of Business	3
	Description of Business and Properties	4
	Upstream	4
	Downstream	16
	Other Businesses	18
1A.	Risk Factors	19
1B.	Unresolved Staff Comments	22
2.	Properties	22
3.	Legal Proceedings	22
4.	Mine Safety Disclosures	23
PART II
5.	Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
6.	Selected Financial Data	24
7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
7A.	Quantitative and Qualitative Disclosures About Market Risk	24
8.	Financial Statements and Supplementary Data	24
9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	24
9A.	Controls and Procedures	25
9B.	Other Information	25
PART III
10.	Directors, Executive Officers and Corporate Governance	26
11.	Executive Compensation	27
12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	27
13.	Certain Relationships and Related Transactions, and Director Independence	27
14.	Principal Accounting Fees and Services	27
PART IV
15.	Exhibits, Financial Statement Schedules	102
	Schedule II — Valuation and Qualifying Accounts	102
16.	Form 10-K Summary	102
	Signatures	105



EX-10.6	EX-24.9
EX-10.7	EX-24.10
EX-10.23	EX-31.1
EX-12.1	EX-31.2
EX-21.1	EX-32.1
EX-23.1	EX-32.2
EX-24.1	EX-99.1
EX-24.2	EX-101 INSTANCE DOCUMENT
EX-24.3	EX-101 SCHEMA DOCUMENT
EX-24.4	EX-101 CALCULATION LINKBASE DOCUMENT
EX-24.5	EX-101 LABELS LINKBASE DOCUMENT
EX-24.6	EX-101 PRESENTATION LINKBASE DOCUMENT
EX-24.7	EX-101 DEFINITION LINKBASE DOCUMENT
EX-24.8

CAUTIONARY STATEMENT RELEVANT TO FORWARD-LOOKING INFORMATION
FOR THE PURPOSE OF “SAFE HARBOR” PROVISIONS OF THE
PRIVATE SECURITIES LITIGATION REFORM ACT OF 1995

This Annual Report on Form 10-K of Chevron Corporation contains forward-looking statements relating to Chevron’s operations that are based on management’s current expectations, estimates and projections about the petroleum, chemicals and other energy-related industries. Words or phrases such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “forecasts,” “projects,” “believes,” “seeks,” “schedules,” “estimates,” “positions,” “pursues,” “may,” “could,” “should,” “budgets,” “outlook,” “trends,” “guidance,” “focus,” “on schedule,” “on track,” “is slated,” “goals,” “objectives,” “strategies,” “opportunities” and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, many of which are beyond the company’s control and are difficult to predict. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward- looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this report. Unless legally required, Chevron undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Among the important factors that could cause actual results to differ materially from those in the forward-looking statements are: changing crude oil and natural gas prices; changing refining, marketing and chemicals margins; the company's ability to realize anticipated cost savings and expenditure reductions; actions of competitors or regulators; timing of exploration expenses; timing of crude oil liftings; the competitiveness of alternate-energy sources or product substitutes; technological developments; the results of operations and financial condition of the company's suppliers, vendors, partners and equity affiliates, particularly during extended periods of low prices for crude oil and natural gas; the inability or failure of the company’s joint-venture partners to fund their share of operations and development activities; the potential failure to achieve expected net production from existing and future crude oil and natural gas development projects; potential delays in the development, construction or start-up of planned projects; the potential disruption or interruption of the company’s operations due to war, accidents, political events, civil unrest, severe weather, cyber threats and terrorist acts, crude oil production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries, or other natural or human causes beyond its control; changing economic, regulatory and political environments in the various countries in which the company operates; general domestic and international economic and political conditions; the potential liability for remedial actions or assessments under existing or future environmental regulations and litigation; significant operational, investment or product changes required by existing or future environmental statutes and regulations, including international agreements and national or regional legislation and regulatory measures to limit or reduce greenhouse gas emissions; the potential liability resulting from other pending or future litigation; the company’s future acquisition or disposition of assets or shares or the delay or failure of such transactions to close based on required closing conditions; the potential for gains and losses from asset dispositions or impairments; government-mandated sales, divestitures, recapitalizations, industry-specific taxes, changes in fiscal terms or restrictions on scope of company operations; foreign currency movements compared with the U.S. dollar; material reductions in corporate liquidity and access to debt markets; the impact of the 2017 U.S. tax legislation on the company's future results; the effects of changed accounting rules under generally accepted accounting principles promulgated by rule-setting bodies; the company's ability to identify and mitigate the risks and hazards inherent in operating in the global energy industry; and the factors set forth under the heading “Risk Factors” on pages 19 through 22 in this report. Other unpredictable or unknown factors not discussed in this report could also have material adverse effects on forward-looking statements.

PART I

Item 1. Business

General Development of Business

Summary Description of Chevron

Chevron Corporation,^* a Delaware corporation, manages its investments in subsidiaries and affiliates and provides administrative, financial, management and technology support to U.S. and international subsidiaries that engage in integrated energy and chemicals operations. Upstream operations consist primarily of exploring for, developing and producing crude oil and natural gas; processing, liquefaction, transportation and regasification associated with liquefied natural gas; transporting crude oil by major international oil export pipelines; transporting, storage and marketing of natural gas; and a gas-to-liquids plant. Downstream operations consist primarily of refining crude oil into petroleum products; marketing of crude oil and refined products; transporting crude oil and refined products by pipeline, marine vessel, motor equipment and rail car; and manufacturing and marketing of commodity petrochemicals, plastics for industrial uses and fuel and lubricant additives.

A list of the company’s major subsidiaries is presented on page E-2. As of December 31, 2017, Chevron had approximately 51,900 employees (including about 3,300 service station employees). Approximately 25,200 employees (including about 3,100 service station employees), or 49 percent, were employed in U.S. operations.

Overview of Petroleum Industry

Petroleum industry operations and profitability are influenced by many factors. Prices for crude oil, natural gas, petroleum products and petrochemicals are generally determined by supply and demand. Production levels from the members of the Organization of Petroleum Exporting Countries (OPEC), Russia and the United States are the major factors in determining worldwide supply. Demand for crude oil and its products and for natural gas is largely driven by the conditions of local, national and global economies, although weather patterns and taxation relative to other energy sources also play a significant part. Laws and governmental policies, particularly in the areas of taxation, energy and the environment, affect where and how companies conduct their operations and formulate their products and, in some cases, limit their profits directly.

Strong competition exists in all sectors of the petroleum and petrochemical industries in supplying the energy, fuel and chemical needs of industry and individual consumers. Chevron competes with fully integrated, major global petroleum companies, as well as independent and national petroleum companies, for the acquisition of crude oil and natural gas leases and other properties and for the equipment and labor required to develop and operate those properties. In its downstream business, Chevron competes with fully integrated, major petroleum companies, as well as independent refining, marketing, transportation and chemicals entities and national petroleum companies, in the sale or acquisition of various goods or services in many national and international markets.

Operating Environment

Refer to pages 30 through 37 of this Form 10-K in Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company’s current business environment and outlook.

Chevron’s Strategic Direction

Chevron’s primary objective is to deliver industry-leading results and superior shareholder value in any business environment. In the upstream, the company’s strategy is to deliver industry-leading returns while developing high-value resource opportunities. In the downstream, the company's strategy is to grow earnings across the value chain and make targeted investments to lead the industry in returns.

Information about the company is available on the company’s website at www.chevron.com. Information contained on the company’s website is not part of this Annual Report on Form 10-K. The company’s Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 are available free of charge on the company’s website soon after such reports are filed with or furnished to the U.S. Securities and Exchange Commission (SEC). The reports are also available on the SEC’s website at www.sec.gov.

________________________________________________________

^* Incorporated in Delaware in 1926 as Standard Oil Company of California, the company adopted the name Chevron Corporation in 1984 and ChevronTexaco Corporation in 2001. In 2005, ChevronTexaco Corporation changed its name to Chevron Corporation. As used in this report, the term “Chevron” and such terms as “the company,” “the corporation,” “our,” “we,” “us” and "its" may refer to Chevron Corporation, one or more of its consolidated subsidiaries, or all of them taken as a whole, but unless stated otherwise they do not include “affiliates” of Chevron — i.e., those companies accounted for by the equity method (generally owned 50 percent or less) or investments accounted for by the cost method. All of these terms are used for convenience only and are not intended as a precise description of any of the separate companies, each of which manages its own affairs.

Description of Business and Properties

The upstream and downstream activities of the company and its equity affiliates are widely dispersed geographically, with operations and projects^* in North America, South America, Europe, Africa, Asia and Australia. Tabulations of segment sales and other operating revenues, earnings and income taxes for the three years ending December 31, 2017, and assets as of the end of 2017 and 2016 — for the United States and the company’s international geographic areas — are in Note 15 to the Consolidated Financial Statements beginning on page 67. Similar comparative data for the company’s investments in and income from equity affiliates and property, plant and equipment are in Note 16 beginning on page 70 and Note 24 on page 87. Refer to page 41 of this Form 10-K in Management's Discussion and Analysis of Financial Condition and Results of Operations for a discussion of the company's capital and exploratory expenditures.

Upstream

Reserves

Refer to Table V beginning on page 95 for a tabulation of the company’s proved net liquids (including crude oil, condensate, natural gas liquids and synthetic oil) and natural gas reserves by geographic area, at the beginning of 2015 and each year-end from 2015 through 2017. Reserves governance, technologies used in establishing proved reserves additions, and major changes to proved reserves by geographic area for the three-year period ended December 31, 2017, are summarized in the discussion for Table V. Discussion is also provided regarding the nature of, status of, and planned future activities associated with the development of proved undeveloped reserves. The company recognizes reserves for projects with various development periods, sometimes exceeding five years. The external factors that impact the duration of a project include scope and complexity, remoteness or adverse operating conditions, infrastructure constraints, and contractual limitations.

At December 31, 2017, 24 percent of the company's net proved oil-equivalent reserves were located in the United States, 21 percent were located in Australia and 20 percent were located in Kazakhstan.

The net proved reserve balances at the end of each of the three years 2015 through 2017 are shown in the following table:



	At December 31
	2017	2016	2015
Liquids — Millions of barrels
Consolidated Companies	4,530	4,131	4,262
Affiliated Companies	2,012	2,197	2,000
Total Liquids	6,542	6,328	6,262
Natural Gas — Billions of cubic feet
Consolidated Companies	27,514	25,432	25,946
Affiliated Companies	3,222	3,328	3,491
Total Natural Gas	30,736	28,760	29,437
Oil-Equivalent — Millions of barrels^*
Consolidated Companies	9,116	8,369	8,586
Affiliated Companies	2,549	2,752	2,582
Total Oil-Equivalent	11,665	11,121	11,168

^* Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.

________________________________________________________

As used in this report, the term “project” may describe new upstream development activity, individual phases in a multiphase development, maintenance activities, certain existing assets, new investments in downstream and chemicals capacity, investments in emerging and sustainable energy activities, and certain other activities. All of these terms are used for convenience only and are not intended as a precise description of the term “project” as it relates to any specific governmental law or regulation.

Net Production of Liquids and Natural Gas

The following table summarizes the net production of liquids and natural gas for 2017 and 2016 by the company and its affiliates. Worldwide oil-equivalent production of 2.728 million barrels per day in 2017 was up 5 percent from 2016. Production increases from major capital projects, base business, and shale and tight properties, were partially offset by production entitlement effects in several locations, normal field declines, and the impact of asset sales. Refer to the “Results of Operations” section beginning on page 34 for a detailed discussion of the factors explaining the 2015 through 2017 changes in production for crude oil and natural gas liquids, and natural gas, and refer to Table V on pages 98 and 99 for information on annual production by geographical region.



			Components of Oil-Equivalent
	Oil-Equivalent		Liquids		Natural Gas
Thousands of barrels per day (MBPD)	(MBPD)¹		(MBPD)		(MMCFPD)
Millions of cubic feet per day (MMCFPD)	2017	2016	2017	2016	2017	2016
United States	681	691	519	504	970	1,120
Other Americas
Argentina	23	26	19	20	27	32
Brazil	13	16	12	16	4	5
Canada²	98	92	87	83	65	55
Colombia	16	21	—	—	96	127
Trinidad and Tobago³	5	12	—	—	29	74
Total Other Americas	155	167	118	119	221	293
Africa
Angola	112	114	103	106	57	52
Democratic Republic of the Congo	2	2	2	2	1	1
Nigeria	250	235	213	208	223	159
Republic of Congo	38	25	36	23	14	11
Total Africa	402	376	354	339	295	223
Asia
Azerbaijan	25	32	23	30	11	13
Bangladesh	111	114	4	4	642	658
China	30	27	17	18	81	51
Indonesia	164	203	137	173	163	182
Kazakhstan	55	62	33	37	132	154
Myanmar	19	21	—	—	116	128
Partitioned Zone⁴	—	—	—	—	—	—
Philippines	25	26	3	3	129	138
Thailand	241	245	69	71	1,031	1,051
Total Asia	670	730	286	336	2,305	2,375
Australia/Oceania
Australia	256	124	27	21	1,372	615
Total Australia/Oceania	256	124	27	21	1,372	615
Europe
Denmark	23	22	14	14	53	48
United Kingdom	75	64	50	43	155	122
Total Europe	98	86	64	57	208	170
Total Consolidated Companies	2,262	2,174	1,368	1,376	5,371	4,796
Affiliates^2,5	466	420	355	343	661	456
Total Including Affiliates⁶	2,728	2,594	1,723	1,719	6,032	5,252

¹Oil-equivalent conversion ratio is 6,000 cubic feet of natural gas = 1 barrel of crude oil.
² Includes synthetic oil: Canada, net	51	50	51	50	—	—
Venezuelan affiliate, net	28	28	28	28	—	—
³ Producing fields in Trinidad and Tobago were sold in August 2017.
⁴ Located between Saudi Arabia and Kuwait. Production has been shut-in since May 2015.
⁵Volumes represent Chevron’s share of production by affiliates, including Tengizchevroil in Kazakhstan; Petroboscan, Petroindependiente and Petropiar in Venezuela; and Angola LNG in Angola.
⁶ Volumes include natural gas consumed in operations of 565 million and 486million cubic feet per day in 2017 and 2016, respectively. Total “as sold” natural gas volumes were 5,467 million and 4,766 million cubic feet per day for 2017 and 2016, respectively.

Production Outlook

The company estimates its average worldwide oil-equivalent production in 2018 will grow 4 to 7 percent compared to 2017, assuming a Brent crude oil price of $60 per barrel and excluding the impact of anticipated 2018 asset sales. This estimate is subject to many factors and uncertainties, as described beginning on page 32. Refer to the “Review of Ongoing Exploration and Production Activities in Key Areas,” beginning on page 8, for a discussion of the company’s major crude oil and natural gas development projects.

Average Sales Prices and Production Costs per Unit of Production

Refer to Table IV on page 94 for the company’s average sales price per barrel of crude oil, condensate and natural gas liquids and per thousand cubic feet of natural gas produced, and the average production cost per oil-equivalent barrel for 2017, 2016 and 2015.

Gross and Net Productive Wells

The following table summarizes gross and net productive wells at year-end 2017 for the company and its affiliates:



	At December 31, 2017
	Productive Oil Wells*		Productive Gas Wells *
	Gross	Net	Gross	Net
United States	43,170	29,690	3,273	2,380
Other Americas	1,049	644	129	76
Africa	1,683	639	20	8
Asia	14,958	12,891	3,780	2,182
Australia/Oceania	564	315	95	26
Europe	325	71	170	36
Total Consolidated Companies	61,749	44,250	7,467	4,708
Affiliates	1,583	550	7	2
Total Including Affiliates	63,332	44,800	7,474	4,710
Multiple completion wells included above	819	551	38	32
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.

Acreage

At December 31, 2017, the company owned or had under lease or similar agreements undeveloped and developed crude oil and natural gas properties throughout the world. The geographical distribution of the company’s acreage is shown in the following table:



	Undeveloped²		Developed		Developed and Undeveloped
Thousands of acres¹	Gross	Net	Gross	Net	Gross	Net
United States	4,004	3,415	4,189	2,966	8,193	6,381
Other Americas	26,249	14,635	1,183	264	27,432	14,899
Africa	8,432	3,474	2,243	933	10,675	4,407
Asia	23,243	11,637	1,720	975	24,963	12,612
Australia/Oceania	25,947	17,198	2,002	803	27,949	18,001
Europe	2,004	1,004	407	53	2,411	1,057
Total Consolidated Companies	89,879	51,363	11,744	5,994	101,623	57,357
Affiliates	513	224	291	112	804	336
Total Including Affiliates	90,392	51,587	12,035	6,106	102,427	57,693
¹ Gross acres represent the total number of acres in which Chevron has an ownership interest. Net acres represent the sum of Chevron's ownership interest in gross acres.
²The gross undeveloped acres that will expire in 2018, 2019 and 2020 if production is not established by certain required dates are 4,353, 1,695 and 1,321, respectively.

Delivery Commitments

The company sells crude oil and natural gas from its producing operations under a variety of contractual obligations. Most contracts generally commit the company to sell quantities based on production from specified properties, but some natural gas sales contracts specify delivery of fixed and determinable quantities, as discussed below.

In the United States, the company is contractually committed to deliver 151 billion cubic feet of natural gas to third parties from 2018 through 2020. The company believes it can satisfy these contracts through a combination of equity production from the company’s proved developed U.S. reserves and third-party purchases. These commitments are all based on contracts with indexed pricing terms.

Outside the United States, the company is contractually committed to deliver a total of 2,380 billion cubic feet of natural gas to third parties from 2018 through 2020 from operations in Australia, Colombia, Denmark, Indonesia and the Philippines. These sales contracts contain variable pricing formulas that are generally referenced to the prevailing market price for crude oil, natural gas or other petroleum products at the time of delivery. The company believes it can satisfy these contracts from quantities available from production of the company’s proved developed reserves in these countries.

Development Activities

Refer to Table I on page 91 for details associated with the company’s development expenditures and costs of proved property acquisitions for 2017, 2016 and 2015.

The following table summarizes the company’s net interest in productive and dry development wells completed in each of the past three years, and the status of the company’s development wells drilling at December 31, 2017. A “development well” is a well drilled within the known area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.



	Wells Drilling*		Net Wells Completed
	at 12/31/17		2017		2016		2015
	Gross	Net	Prod.	Dry	Prod.	Dry	Prod.	Dry
United States	220	167	435	4	420	4	873	3
Other Americas	30	13	40	—	45	—	99	—
Africa	4	1	34	—	17	—	9	—
Asia	9	1	246	2	470	6	828	5
Australia/Oceania	—	—	—	—	4	—	4	—
Europe	2	—	4	—	3	—	2	—
Total Consolidated Companies	265	182	759	6	959	10	1,815	8
Affiliates	41	17	36	—	38	—	26	—
Total Including Affiliates	306	199	795	6	997	10	1,841	8
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.

Exploration Activities

Refer to Table I on page 91 for detail on the company’s exploration expenditures and costs of unproved property acquisitions for 2017, 2016 and 2015.

The following table summarizes the company’s net interests in productive and dry exploratory wells completed in each of the last three years, and the number of exploratory wells drilling at December 31, 2017. “Exploratory wells” are wells drilled to find and produce crude oil or natural gas in unknown areas and include delineation and appraisal wells, which are wells drilled to find a new reservoir in a field previously found to be productive of crude oil or natural gas in another reservoir or to extend a known reservoir.



	Wells Drilling*		Net Wells Completed
	at 12/31/17		2017		2016		2015
	Gross	Net	Prod.	Dry	Prod.	Dry	Prod.	Dry
United States	6	3	7	1	4	1	16	4
Other Americas	1	1	—	—	4	—	5	1
Africa	—	—	—	—	1	1	3	—
Asia	1	1	—	—	3	—	5	1
Australia/Oceania	—	—	—	—	—	—	1	4
Europe	—	—	—	1	—	—	3	—
Total Consolidated Companies	8	5	7	2	12	2	33	10
Affiliates	—	—	—	—	—	—	—	—
Total Including Affiliates	8	5	7	2	12	2	33	10
* Gross wells represent the total number of wells in which Chevron has an ownership interest. Net wells represent the sum of Chevron's ownership interest in gross wells.

Review of Ongoing Exploration and Production Activities in Key Areas

Chevron has exploration and production activities in most of the world's major hydrocarbon basins. Chevron’s 2017 key upstream activities, some of which are also discussed in Management’s Discussion and Analysis of Financial Condition and Results of Operations, beginning on page 34, are presented below. The comments include references to “total production” and “net production,” which are defined under “Production” in Exhibit 99.1 on page E-8.

The discussion that follows references the status of proved reserves recognition for significant long-lead-time projects not on production as well as for projects recently placed on production. Reserves are not discussed for exploration activities or recent discoveries that have not advanced to a project stage, or for mature areas of production that do not have individual projects requiring significant levels of capital or exploratory investment. Amounts indicated for project costs represent total project costs, not the company’s share of costs for projects that are less than wholly owned.

United States

Upstream activities in the United States are primarily located in the midcontinent region, the Gulf of Mexico, California and the Appalachian Basin. Net oil-equivalent production in the United States during 2017 averaged 681,000 barrels per day.

The company's activities in the midcontinent region are primarily in Colorado, New Mexico and Texas. During 2017, net daily production in these areas averaged 134,000 barrels of crude oil, 505 million cubic feet of natural gas and 50,000 barrels of natural gas liquids (NGLs). In 2017, the company divested properties in areas including Colorado, New Mexico, Oklahoma and Texas. The company is pursuing selected opportunities and actively transacting to create value.

In the Permian Basin of West Texas and southeast New Mexico, the company holds approximately 500,000 and 1,200,000 net acres of shale and tight resources in the Midland and Delaware basins, respectively. This acreage includes multiple stacked formations that enable production from several layers of rock in different geologic zones. The stacked plays multiply the basin’s resource and economic potential by allowing for multiple horizontal wells to be developed from a single pad location using shared facilities and infrastructure, which reduces development costs and improves capital efficiency. Chevron has implemented a factory development strategy in the basin, which utilizes multiwell pads to drill a series of horizontal wells that are completed concurrently using hydraulic fracture stimulation. In 2017, the company deployed a new basis of design, resulting in improved economics. The company is also applying data analytics and petrophysical technology on its Permian well information to drive improvements in well targets and performance. The company drilled 130 wells and participated in 180 nonoperated wells in the Midland and Delaware basins in 2017.

During 2017, net daily production in the Gulf of Mexico averaged 165,000 barrels of crude oil, 122 million cubic feet of natural gas and 13,000 barrels of NGLs. In 2017, the company divested its remaining operated offshore assets in the shelf area. All remaining shelf assets are non-operated interests. Chevron is also engaged in various exploration, development and production activities in the deepwater Gulf of Mexico.

The deepwater Jack and St. Malo fields are being jointly developed with a host floating production unit (FPU) located between the two fields. Chevron has a 50 percent interest in the Jack Field and a 51 percent interest in the St. Malo Field. Both fields are company operated. The company has a 40.6 percent interest in the production host facility, which is designed to accommodate production from the Jack/St. Malo development and third-party tiebacks. Total daily production from the Jack and St. Malo fields in 2017 averaged 116,000 barrels of liquids (59,000 net) and 18 million cubic feet of natural gas (9 million net). Production ramp-up and development drilling for the first development phase was completed in 2017. In addition, development drilling continued on Stage 2, the second phase of the development plan, with three of the four planned wells completed. Stage 3 includes three additional development wells. Stage 3 drilling began in second quarter 2017; execution is expected to continue in 2018. Proved reserves have been recognized for these phases. Production from the Jack/St. Malo development is expected to ramp up to a total daily rate of 142,000 barrels of crude oil and 36 million cubic feet of natural gas. The Jack and St. Malo fields have an estimated remaining production life of 30 years.

At the 58 percent-owned and operated deepwater Tahiti Field, net daily production averaged 45,000 barrels of crude oil, 18 million cubic feet of natural gas, and 3,000 barrels of NGLs. Infill drilling continued in 2017. The Tahiti Vertical Expansion Project is the next development phase of the Tahiti Field, developing shallower reservoirs and encompassing four new wells and associated subsea infrastructure. All wells have been drilled, and facility installation work has commenced. First oil is expected in second-half 2018. Proved reserves have been recognized for this project. The Tahiti Field has an estimated production life of at least 20 years.

The company has a 15.6 percent nonoperated working interest in the deepwater Mad Dog Field. In 2017, net daily production averaged 8,000 barrels of liquids and 1 million cubic feet of natural gas. The next development phase, the Mad Dog 2 Project, is planned to develop the southwestern extension of the Mad Dog Field. The development plan includes a new

floating production platform with a design capacity of 140,000 barrels of crude oil per day. A final investment decision was reached in February 2017. First oil is expected in 2021. At the end of 2017, proved reserves have been recognized for the Mad Dog 2 Project.

The development plan for the 60 percent-owned and operated deepwater Big Foot Project includes a 15-slot drilling and production tension leg platform (TLP) with water injection facilities and a design capacity of 75,000 barrels of crude oil and 25 million cubic feet of natural gas per day. The TLP has been moored in its final location; installation is expected to be completed in second quarter 2018. First oil is expected in late 2018. The field has an estimated production life of 35 years from the time of start-up. Proved reserves have been recognized for this project.

Chevron holds a 25 percent nonoperated working interest in the Stampede Project, the unitized development of the deepwater Knotty Head and Pony discoveries. The planned facilities have a design capacity of 80,000 barrels of crude oil and 40 million cubic feet of natural gas per day. Installation of the TLP and subsea infrastructure was completed in 2017, with first oil achieved in January 2018. The field has an estimated production life of 30 years from the time of start-up. Proved reserves have been recognized for this project.

During 2017 and early 2018, the company participated in two appraisal wells and four exploration wells in the deepwater Gulf of Mexico. Chevron has operated working interests of 55 to 61.3 percent in the blocks containing the Anchor Field. The appraisal drilling program for the Anchor Field concluded in 2017 with the successful Anchor appraisal well. The company filed for Suspension of Production (SOP) in January 2018. The SOP is intended to hold the associated leases as the planned development matures. Activities are underway to mature a cost effective development plan.

Chevron is the operator of an exploration and appraisal program and potential development named Tigris, covering several jointly held offshore leases in the northwest portion of Keathley Canyon. This area may have the potential to support a cost-effective, deepwater hub development of multiple fields to a new central host. Activities are underway to mature the development plan. Exploration and appraisal activities have been completed at the 50 percent-owned Tiber and Guadalupe fields. The company has obtained an SOP for the Tiber Unit, and recently filed for an SOP on the Guadalupe Unit. Adjacent leases containing the Gibson prospect are expected to be part of the development.

During 2017 and early 2018, the company participated in successful discovery and appraisal wells at the nonoperated Whale prospect in the Perdido area, which resulted in a significant crude oil discovery. Chevron has a 40 percent working interest in the Whale prospect. Chevron announced a significant crude oil discovery in the 60 percent-owned and operated Ballymore prospect in January 2018. Ballymore is located in the Mississippi Canyon area, approximately 3 miles from Chevron's Blind Faith Platform. A sidetrack well is currently being drilled to further assess the discovery.

Chevron added 35 leases to its deepwater portfolio as a result of awards from the central Gulf of Mexico Lease Sale 247, held in March 2017, and Lease Sale 249, held in August 2017. Chevron also added 10 additional leases through asset swaps.

In California, the company has significant production in the San Joaquin Valley. In 2017, net daily production averaged 148,000 barrels of crude oil, 53 million cubic feet of natural gas and 2,000 barrels of NGLs.

The company holds approximately 423,000 net acres in the Marcellus Shale and 450,000 net acres in the Utica Shale, primarily located in southwestern Pennsylvania, eastern Ohio and the West Virginia panhandle. During 2017, net daily production in these areas averaged 290 million cubic feet of natural gas, 5,000 barrels of NGLs and 2,000 barrels of condensate. Chevron has implemented a factory development strategy, which enables co-development of the Marcellus and Utica shales from the same pads in stacked play locations.

Other Americas

“Other Americas” includes Argentina, Brazil, Canada, Colombia, Greenland, Mexico, Suriname and Venezuela. Net oil-equivalent production from these countries averaged 210,000 barrels per day during 2017.

Canada Upstream activities in Canada are concentrated in Alberta, British Columbia and the offshore Atlantic region. The company also has exploration interests in the Beaufort Sea region of the Northwest Territories. Net oil-equivalent production during 2017 averaged 98,000 barrels per day, composed of 36,000 barrels of crude oil, 65 million cubic feet of natural gas and 51,000 barrels of synthetic oil from oil sands.

Chevron holds a 26.9 percent nonoperated working interest in the Hibernia Field and a 23.7 percent nonoperated working interest in the unitized Hibernia Southern Extension (HSE) areas offshore Atlantic Canada.

The company holds a 29.6 percent nonoperated working interest in the heavy oil Hebron Field, also offshore Atlantic Canada. The development plan includes a platform with a design capacity of 150,000 barrels of crude oil per day. The

platform was installed at the offshore location in June 2017. First oil was achieved in November 2017. The project has an expected economic life of 30 years.

In the Flemish Pass Basin offshore Newfoundland, Chevron holds a 40 percent nonoperated working interest in two exploration blocks, EL1125 and EL1126. In addition, the company holds a 35 percent-owned and operated interest in Block EL1138.

The company holds a 20 percent nonoperated working interest in the Athabasca Oil Sands Project (AOSP) in Alberta. Oil sands are mined from both the Muskeg River and the Jackpine mines, and bitumen is extracted from the oil sands and upgraded into synthetic oil. Carbon dioxide emissions from the upgrade process are reduced by the Quest carbon capture and storage facilities.

The company holds approximately 228,000 net acres in the Duvernay Shale in Alberta. Chevron has a 70 percent-owned and operated interest in most of the Duvernay acreage. Drilling continued during 2017 on an appraisal and land retention program. In November 2017, Chevron announced plans for the initial development program on approximately 55,000 net acres of its operated position in the Duvernay play. A total of 92 wells had been tied into production facilities by early 2018.

Chevron holds a 50 percent-owned and operated interest in the proposed Kitimat LNG and Pacific Trail Pipeline projects and a 50 percent interest in 290,000 net acres in the Horn River and Liard shale gas basins in British Columbia. The horizontal appraisal drilling program progressed during 2017. The Kitimat LNG Project is planned to include a two-train LNG facility and has a 10.0 million-metric-ton-per-year export license. The total production capacity for the project is expected to be 1.6 billion cubic feet of natural gas per day. Spending is being paced until LNG market conditions and reductions in project costs are sufficient to support the development of this project. At the end of 2017, proved reserves had not been recognized for this project.

Greenland Chevron held a 29.2 percent-owned and operated interest in two exploration blocks off the northeast coast of Greenland. The company informed the government of Greenland of its intent to relinquish these blocks in late 2017 following completion of a multi-year seismic program.

Mexico The company operates and holds a 33.3 percent working interest in Block 3 in the Perdido area of the Gulf of Mexico. The block covers 139,000 net acres. In 2017, activities for a seismic reprocessing project began. Chevron continues to evaluate additional exploration opportunities. In January 2018, a Chevron-led consortium was the successful bidder on an exploration license for Block 22 in the deepwater Cuenca Salina area of the Gulf of Mexico. Following license execution expected in May 2018, the company will operate and hold a 37.5 percent working interest in Block 22 which covers 267,000 net acres.

Argentina Chevron holds a 50 percent nonoperated interest in the Loma Campana and Narambuena concessions in the Vaca Muerta Shale covering 73,000 net acres. Chevron also holds an 85 percent-owned and operated interest in the El Trapial concession covering 94,000 net acres with both conventional production and Vaca Muerta Shale potential. Net oil-equivalent production in 2017 averaged 23,000 barrels per day, composed of 19,000 barrels of crude oil and 27 million cubic feet of natural gas.

Nonoperated development activities continued in 2017 at the Loma Campana concession in the Vaca Muerta Shale. During 2017, 24 horizontal wells were drilled, and the drilling program is expected to continue in 2018.

The company utilizes waterflood operations to mitigate declines at the operated El Trapial Field and continues to evaluate the potential of the Vaca Muerta Shale. The El Trapial concession expires in 2032. Chevron plans to start a shale appraisal program in late 2018.

Evaluation of the nonoperated Narambuena Block continued in 2017. Chevron was the successful bidder in November 2017 on the Loma del Molle Norte Block adjacent to the El Trapial concession.

Brazil Chevron holds interests in the Frade (51.7 percent-owned and operated) and Papa-Terra (37.5 percent, nonoperated) deepwater fields located in the Campos Basin. In June 2017, the concession that includes the Frade Field was extended from 2025 to 2041, contingent on additional field development. The company is progressing a redevelopment plan. The concession that includes the Papa-Terra Field expires in 2032, and the remaining scope of the development plan is under evaluation. Drilling operations restarted at year-end 2017. Net oil-equivalent production in 2017 averaged 13,000 barrels per day, composed of 12,000 barrels of crude oil and 4 million cubic feet of natural gas.

Additionally, Chevron holds a 50 percent-owned and operated interest in Block CE-M715, located in the Ceara Basin offshore Brazil. Final 3-D seismic data was received in second quarter 2017 and is being evaluated.

Colombia The company operates the offshore Chuchupa and onshore Ballena natural gas fields and receives 43 percent of the production for the remaining life of each field. Net production in 2017 averaged 96 million cubic feet of natural gas per day.

Suriname Chevron holds a 33.3 percent and a 50 percent nonoperated working interest in deepwater Blocks 42 and 45 offshore Suriname, respectively. An exploratory well is planned in Block 45 in 2018.

Trinidad and Tobago In August 2017, the company sold its nonoperated working interest in the East Coast Marine Area and its operated interest in the Manatee Field.

Venezuela Chevron's production activities in Venezuela are located in western Venezuela and the Orinoco Belt. Net oil-equivalent production during 2017 averaged 55,000 barrels per day, composed of 52,000 barrels of crude oil, and 15 million cubic feet of natural gas.

Chevron has a 30 percent interest in the Petropiar affiliate that operates the Hamaca heavy oil production and upgrading project located in Venezuela’s Orinoco Belt under an agreement expiring in 2033. Petropiar drilled 70 development wells in 2017. Chevron also holds a 39.2 percent interest in the Petroboscan affiliate that operates the Boscan Field in western Venezuela and a 25.2 percent interest in the Petroindependiente affiliate that operates the LL-652 Field in Lake Maracaibo, both of which are under agreements expiring in 2026. Petroboscan drilled 26 development wells in 2017.

Chevron also holds a 34 percent interest in the Petroindependencia affiliate, which includes the Carabobo 3 heavy oil project located within the Orinoco Belt.

Africa

In Africa, the company is engaged in upstream activities in Angola, Democratic Republic of the Congo, Liberia, Morocco, Nigeria and Republic of Congo. Net oil-equivalent production averaged 453,000 barrels per day during 2017 in this region.

Angola The company operates and holds a 39.2 percent interest in Block 0, a concession adjacent to the Cabinda coastline, and a 31 percent interest in a production-sharing contract (PSC) for deepwater Block 14. The concession for Block 0 extends through 2030 and the development and production rights for the various producing fields in Block 14 expire between 2023 and 2028. During 2017, net production averaged 113,000 barrels of liquids and 302 million cubic feet of natural gas per day.

The main production facility of the second stage of the Mafumeira Field development was brought on line in February 2017 and production ramp-up is expected to continue through 2018. Water injection support began in May 2017, and gas export to Angola LNG began in July 2017.

Chevron has a 36.4 percent interest in Angola LNG Limited, which operates an onshore natural gas liquefaction plant in Soyo, Angola. The plant has the capacity to process 1.1 billion cubic feet of natural gas per day. This is the world's first LNG plant supplied with associated gas, where the natural gas is a byproduct of crude oil production. Feedstock for the plant originates from multiple fields and operators. Total daily production in 2017 averaged 674 million cubic feet of natural gas (245 million net) and 27,000 barrels of NGLs (10,000 barrels net).

Angola-Republic of Congo Joint Development Area Chevron operates and holds a 31.3 percent interest in the Lianzi Unitization Zone, located in an area shared equally by Angola and Republic of Congo. Production from Lianzi is reflected in the totals for Angola and Republic of Congo.

Democratic Republic of the Congo Chevron has a 17.7 percent nonoperated working interest in an offshore concession. In December 2017, the concession was extended 20 years, until 2043. Net production in 2017 averaged 2,000 barrels of crude oil per day.

Republic of Congo Chevron has a 31.5 percent nonoperated working interest in the offshore Haute Mer permit areas (Nkossa, Nsoko and Moho-Bilondo). The licenses for Nsoko, Nkossa, and Moho-Bilondo expire in 2018, 2027 and 2030, respectively. Net production averaged 36,000 barrels of liquids per day in 2017.

In March 2017, production started at the new TLP and floating production unit (FPU) facilities hub in the Moho-Bilondo development area. Miocene and Albian development drilling continued in 2017. Total daily production in 2017 averaged 72,000 barrels of crude oil (20,000 barrels net).

Two exploration wells are planned to be drilled in 2018, with one in the Moho Bilondo area and one in the 20.4 percent nonoperated working interest Haute Mer B area.

Liberia Chevron operates and holds a 45 percent interest in Block LB-14 off the coast of Liberia. The LB-14 PSC expires in 2018.

Morocco The company holds a 45 percent interest in two operated deepwater areas offshore Morocco. In 2017, the evaluation of 3-D seismic data continued. In 2017, the company surrendered its interest in the Cap Rhir Deep acreage.

Nigeria Chevron holds a 40 percent interest in eight operated concessions in the onshore and near-offshore regions of the Niger Delta. The company also holds acreage positions in three operated and six nonoperated deepwater blocks, with working interests ranging from 20 percent to 100 percent. In 2017, the company’s net oil-equivalent production in Nigeria averaged 250,000 barrels per day, composed of 207,000 barrels of crude oil, 223 million cubic feet of natural gas and 6,000 barrels of liquefied petroleum gas.

Chevron operates and holds a 67.3 percent interest in the Agbami Field, located in deepwater Oil Mining Lease (OML) 127 and OML 128. The first two phases of infill drilling, Agbami 2 and Agbami 3, are complete. The third phase of infill drilling has commenced to further offset field decline. The leases that contain the Agbami Field expire in 2023 and 2024.

Also in the deepwater area, the Aparo Field in OML 132 and OML 140 and the third-party-owned Bonga SW Field in OML 118 share a common geologic structure and are planned to be jointly developed. Chevron holds a 16.6 percent nonoperated working interest in the unitized area. The development plan involves subsea wells tied back to a floating production, storage and offloading vessel (FPSO). Work continues on optimizing project scope and cost. At the end of 2017, no proved reserves were recognized for this project.

In deepwater exploration, Chevron operates and holds a 55 percent interest in the deepwater Nsiko discoveries in OML 140. A 3-D seismic acquisition is planned for OML 140 in 2018. Chevron also holds a 30 percent nonoperated working interest in OML 138, which includes the Usan Field and several satellite discoveries, and a 27 percent interest in adjacent licenses OML 139 and Oil Prospecting License (OPL) 223. In 2017, the company continued to evaluate development options for the multiple discoveries in the Usan area, including the Owowo Field that straddles OML 139 and OPL 223.

In the Niger Delta region, Chevron is executing a 36-well infill drilling program to offset oil decline and increase production. The program achieved net production of 13,000 barrels of crude oil per day at the end of 2017. The company is the operator of the Escravos Gas Plant (EGP) with a total processing capacity of 680 million cubic feet per day of natural gas and an LPG and condensate export capacity of 58,000 barrels per day. The company is also the operator of the 33,000-barrel-per-day Escravos gas-to-liquids facility. Optimization of these facilities continued in 2017. Construction activities were completed in 2017 on the 40 percent-owned and operated Sonam Field Development Project, which is designed to process natural gas through the EGP facilities and is expected to deliver 215 million cubic feet of natural gas per day to the domestic market and produce a total of 30,000 barrels of liquids per day. Production commenced in June 2017 and is expected to continue ramping up in 2018.

In addition, the company holds a 36.7 percent interest in the West African Gas Pipeline Company Limited affiliate, which supplies Nigerian natural gas to customers in Benin, Ghana and Togo.

Asia

In Asia, the company is engaged in upstream activities in Azerbaijan, Bangladesh, China, Indonesia, Kazakhstan, the Kurdistan Region of Iraq, Myanmar, the Partitioned Zone located between Saudi Arabia and Kuwait, the Philippines, Russia, and Thailand. During 2017, net oil-equivalent production averaged 1,030,000 barrels per day in this region.

Azerbaijan Chevron holds a nonoperated interest in the Azerbaijan International Operating Company (AIOC) and the crude oil production from the Azeri-Chirag-Gunashli (ACG) fields. AIOC operations are conducted under a PSC. In November 2017, the PSC was extended from 2024 to 2049. As part of the extension agreement, the company's interest in AIOC was reduced from 11.3 percent to 9.6 percent. Net oil-equivalent production in 2017 averaged 25,000 barrels per day, composed of 23,000 barrels of crude oil and 11 million cubic feet of natural gas.

Chevron also has an 8.9 percent interest in the Baku-Tbilisi-Ceyhan (BTC) pipeline affiliate, which transports the majority of ACG production from Baku, Azerbaijan, through Georgia to Mediterranean deepwater port facilities at Ceyhan, Turkey. The BTC pipeline has a capacity of 1 million barrels per day. Another production export route for crude oil is the Western Route Export Pipeline (WREP), which is operated by AIOC. During 2017, WREP transported approximately 77,000 barrels per day from Baku, Azerbaijan, to a marine terminal at Supsa, Georgia, on the Black Sea.

Kazakhstan Chevron has a 50 percent interest in the Tengizchevroil (TCO) affiliate and an 18 percent nonoperated working interest in the Karachaganak Field. Net oil-equivalent production in 2017 averaged 415,000 barrels per day, composed of 326,000 barrels of liquids and 533 million cubic feet of natural gas.

TCO is developing the Tengiz and Korolev crude oil fields in western Kazakhstan under a concession agreement that expires in 2033. Net daily production in 2017 from these fields averaged 272,000 barrels of crude oil, 401 million cubic feet of natural gas and 21,000 barrels of NGLs. All of TCO’s crude oil production was exported through the Caspian Pipeline Consortium (CPC) pipeline.

The Future Growth and Wellhead Pressure Management Project (FGP/WPMP) at Tengiz is being managed as a single integrated project. The FGP is designed to increase total daily production by about 260,000 barrels of crude oil and to expand the utilization of sour gas injection technology proven in existing operations to increase ultimate recovery from the reservoir. The WPMP is designed to maintain production levels in existing plants as reservoir pressure declines. Project execution advanced through 2017. Fabrication of process modules is underway, and gas turbine generators are being constructed. Dredging is complete, and other activities for the initiation of port operations are underway. Infrastructure work and site construction are progressing, and three drilling rigs are in operation on the multi-well pads. First oil is planned for 2022. Proved reserves have been recognized for the FGP/WPMP.

The Capacity and Reliability (CAR) Project is designed to reduce facility bottlenecks and increase plant capacity and reliability at Tengiz. Construction activities for the CAR Project progressed during 2017, with project completion projected for second quarter 2018. Proved reserves have been recognized for the CAR Project.

The Karachaganak Field is located in northwest Kazakhstan, and operations are conducted under a PSC that expires in 2038. During 2017, net daily production averaged 33,000 barrels of liquids and 132 million cubic feet of natural gas. Most of the exported liquids were transported through the CPC pipeline. Work continues on identifying the optimal scope for the future expansion of the field. At year-end 2017, proved reserves had not been recognized for a future expansion.

Kazakhstan/Russia Chevron has a 15 percent interest in the CPC. During 2017, CPC transported an average of 1,180,000 barrels of crude oil per day, composed of 1,060,000 barrels per day from Kazakhstan and 120,000 barrels per day from Russia. In 2017, work was completed on the expansion of the pipeline, reaching the design capacity of 1.4 million per day. The expansion provides additional transportation capacity that accommodates a portion of the future growth in TCO production.

Bangladesh Chevron operates and holds a 100 percent interest in Block 12 (Bibiyana Field) and Blocks 13 and 14 (Jalalabad and Moulavi Bazar fields). The rights to produce from Jalalabad expire in 2024, from Moulavi Bazar in 2028 and from Bibiyana in 2034. Net oil-equivalent production in 2017 averaged 111,000 barrels per day, composed of 642 million cubic feet of natural gas and 4,000 barrels of condensate. In third quarter 2017, the company announced its intent to retain its assets in Bangladesh.

Myanmar Chevron has a 28.3 percent nonoperated working interest in a PSC for the production of natural gas from the Yadana, Badamyar and Sein fields, within Blocks M5 and M6, in the Andaman Sea. The PSC expires in 2028. The company also has a 28.3 percent nonoperated interest in a pipeline company that transports natural gas to the Myanmar-Thailand border for delivery to power plants in Thailand. Net natural gas production in 2017 averaged 116 million cubic feet per day.

The Badamyar-Low Compression Platform (LCP) expansion project in Block M5 was brought on line in May 2017. The Badamyar-LCP is designed to maintain production from the Yadana Field by lowering wellhead pressure.

Chevron also holds a 99 percent-owned and operated interest in Block A5. Evaluation of a 3-D seismic survey that was completed in December 2015 continued in 2017. Additional seismic processing and interpretation is expected in 2018.

Thailand Chevron holds operated interests in the Pattani Basin, located in the Gulf of Thailand, with ownership ranging from 35 percent to 80 percent. Concessions for producing areas within this basin expire between 2022 and 2035. Chevron also has a 16 percent nonoperated working interest in the Arthit Field located in the Malay Basin. Concessions for the producing areas within this basin expire between 2036 and 2040. Net oil-equivalent production in 2017 averaged 241,000 barrels per day, composed of 69,000 barrels of crude oil and condensate and 1.0 billion cubic feet of natural gas.

In the Pattani Basin, the 35 percent-owned and operated Ubon Project in Block 12/27 entered front-end engineering and design (FEED) in third quarter 2017 with an updated development concept that optimizes oil and gas production profiles. At the end of 2017, proved reserves have not been recognized for this project.

During 2017, the company drilled two exploration wells in the Malay Basin, and both wells were successful. The company also holds exploration interests in the Thailand-Cambodia overlapping claim area that are inactive, pending resolution of border issues between Thailand and Cambodia.

China Chevron has operated and nonoperated working interests in several areas in China. The company’s net daily production in 2017 averaged 17,000 barrels of crude oil and 81 million cubic feet of natural gas.

The company operates the 49 percent-owned Chuandongbei Project, located onshore in the Sichuan Basin. The Xuanhan Gas Plant has three gas processing trains with a design outlet capacity of 258 million cubic feet per day. Total daily production in 2017 averaged 177 million cubic feet of natural gas (81 million net).

The company also has nonoperated working interests of 24.5 percent in the QHD 32-6 Field and 16.2 percent in Block 11/19 in the Bohai Bay, and 32.7 percent in Block 16/19 in the Pearl River Mouth Basin. The PSCs for these producing assets expire between 2022 and 2028.

Philippines The company holds a 45 percent nonoperated working interest in the Malampaya natural gas field, offshore Philippines. Net oil-equivalent production in 2017 averaged 25,000 barrels per day, composed of 129 million cubic feet of natural gas and 3,000 barrels of condensate. The concession expires in 2024.

In December 2017, the company sold its geothermal assets in the Philippines.

Indonesia Chevron holds working interests through various PSCs in Indonesia. In Sumatra, the company holds a 100 percent-owned and operated interest in the Rokan PSC. Chevron also operates four PSCs in the Kutei Basin, located offshore eastern Kalimantan. These interests range from 62 percent to 92.5 percent. Net oil-equivalent production in 2017 averaged 164,000 barrels per day, composed of 137,000 barrels of liquids and 163 million cubic feet of natural gas. In 2016, Chevron advised the government of Indonesia of its intent not to extend the East Kalimantan PSC and to return the assets to the government upon PSC expiration in fourth quarter 2018.

The largest producing field is Duri, located in the Rokan PSC. Duri has been under steamflood since 1985 and is one of the world’s largest steamflood developments. Infill drilling and workover programs continued in 2017. The Rokan PSC expires in 2021.

There are two deepwater natural gas development projects in the Kutei Basin progressing under a single plan of development. Collectively, these projects are referred to as the Indonesia Deepwater Development. One of these projects, Bangka, includes a two-well subsea tieback to the West Seno FPU. The company’s interest is 62 percent. Net daily production from Bangka in 2017 averaged 49 million cubic feet of natural gas and 2,000 barrels of condensate.

The other project, Gendalo-Gehem, has a planned design capacity of 1.1 billion cubic feet of natural gas and 47,000 barrels of condensate per day. The company's interest is approximately 63 percent. The company continues to work toward a final investment decision, subject to the timing of government approvals, including extension of the associated PSCs, and securing new LNG sales contracts. The project is being reviewed for opportunities to reduce project cost. At the end of 2017, proved reserves have not been recognized for this project.

In March 2017, the company sold its geothermal assets in Indonesia.

In August 2017, the company sold its South Natuna Sea Block B assets in Indonesia.

Kurdistan Region of Iraq The company operates and holds 80 percent contractor interests in the Sarta PSC. In fourth quarter 2017, drilling commenced on the first appraisal well. The well is planned to be completed in second-half 2018.

Partitioned Zone Chevron holds a concession to operate the Kingdom of Saudi Arabia's 50 percent interest in the hydrocarbon resources in the onshore area of the Partitioned Zone between Saudi Arabia and Kuwait. The concession expires in 2039. Beginning in May 2015, production in the Partitioned Zone was shut in as a result of continued difficulties in securing work and equipment permits. As of early 2018, production remains shut in, and the exact timing of a production restart is uncertain and dependent on dispute resolution between Saudi Arabia and Kuwait.

Processing of the 3-D seismic survey, which was acquired in 2016 and covers the entire onshore Partitioned Zone, was completed in second quarter 2017. Work continues to interpret the results.

Australia/Oceania

In Australia/Oceania, the company is engaged in upstream activities in Australia and New Zealand. During 2017, net oil-equivalent production averaged 256,000 barrels per day, all from Australia.

Australia Upstream activities in Australia are concentrated offshore Western Australia, where the company is the operator of two major LNG projects, Gorgon and Wheatstone, and has a nonoperated working interest in the North West Shelf (NWS) Venture and exploration acreage in the Browse Basin and the Carnarvon Basin. The company also holds exploration acreage in the Bight Basin offshore South Australia. During 2017, the company's production averaged 27,000 barrels of liquids and 1.4 billion cubic feet of natural gas per day.

Chevron holds a 47.3 percent interest in and is the operator of the Gorgon Project, which includes the development of the Gorgon and Jansz-Io fields. The project includes a three-train, 15.6 million-metric-ton-per-year LNG facility, a carbon dioxide injection facility and a domestic gas plant, which are located on Barrow Island. The total production capacity for the project is approximately 2.6 billion cubic feet of natural gas and 20,000 barrels of condensate per day. LNG Train 3 start-up was achieved in March 2017. Total daily production from all three trains in 2017 averaged 1.9 billion cubic feet of natural gas (905 million net) and 14,000 barrels of condensate (7,000 barrels net). The project's estimated economic life exceeds 40 years.

Chevron holds an 80.2 percent interest in the offshore licenses and a 64.1 percent interest in the LNG facilities associated with the Wheatstone Project. The project includes the development of the Wheatstone and Iago fields, a two-train, 8.9 million-metric-ton-per-year LNG facility, and a domestic gas plant. The onshore facilities are located at Ashburton North on the coast of Western Australia. The total production capacity for the Wheatstone and Iago fields and nearby third-party fields is expected to be approximately 1.6 billion cubic feet of natural gas and 30,000 barrels of condensate per day. LNG Train 1 start-up and first cargo were achieved in October 2017. Train 2 start-up operations are underway, and first LNG is expected in second quarter 2018. The project's estimated economic life exceeds 30 years.

Chevron has a 16.7 percent nonoperated working interest in the NWS Venture in Western Australia. The concession for the NWS Venture expires in 2034.

During 2017, the company acquired 50 percent operated interests in four additional exploration permits in the northern Carnarvon Basin. Chevron expects to continue to evaluate exploration potential in the Carnarvon Basin during 2018.

The company holds nonoperated working interests ranging from 24.8 percent to 50 percent in three exploration blocks in the Browse Basin.

The company operates and holds a 100 percent interest in offshore Blocks EPP44 and EPP45 in the Bight Basin. In October 2017, the company discontinued the exploration program and informed the Government of Australia of the company's intent to exit from the Bight Basin.

New Zealand Chevron holds a 50 percent interest and operates three deepwater exploration permits in the offshore Pegasus and East Coast basins. Acquisition of 3-D seismic data was completed in second quarter 2017, and processing of the data is continuing.

Europe

In Europe, the company is engaged in upstream activities in Denmark, Norway and the United Kingdom. Net oil-equivalent production averaged 98,000 barrels per day during 2017.

Denmark Chevron holds a 12 percent nonoperated working interest in the Danish Underground Consortium, which produces crude oil and natural gas from 13 North Sea fields. The concession expires in 2042. Net oil-equivalent production in 2017 averaged 23,000 barrels per day, composed of 14,000 barrels of crude oil and 53 million cubic feet of natural gas.

United Kingdom The company’s net oil-equivalent production in 2017 averaged 75,000 barrels per day, composed of 50,000 barrels of liquids and 155 million cubic feet of natural gas.

The Captain Enhanced Oil Recovery Project is the next development phase of the Captain Field and is designed to increase field recovery by injecting a polymer/water mixture. In 2017, two polymer injection pilots were successfully completed and the company reached a final investment decision on Captain EOR Stage 1, which includes an expansion of the existing polymer injection system on the wellhead production platform, six new polymer injection wells and modifications to the platform facilities. At the end of 2017, proved reserves have been recognized for the Stage 1 project. Also during 2017, FEED activities continued to progress on Captain EOR Stage 2, which involves subsea expansion of the technology. At the end of 2017, proved reserves had not been recognized for Stage 2 of the project.

During 2017, hook-up and commissioning activities advanced for the Clair Ridge Project, located west of the Shetland Islands, in which the company has a 19.4 percent nonoperated working interest. The project is the second development phase of the Clair Field. The design capacity of the project is 120,000 barrels of crude oil and 100 million cubic feet of natural gas per day. First production is expected in 2018. The Clair Field has an estimated production life extending until 2050. Proved reserves have been recognized for the Clair Ridge Project.

At the 40 percent-owned and operated Rosebank Project northwest of the Shetland Islands, the selected design is a subsea development tied back to an FPSO with natural gas exported via pipeline. The design capacity of the project is 100,000 barrels of crude oil and 80 million cubic feet of natural gas per day. FEED activities continued to progress in 2017, with focus on subsurface characterization and cost optimization. At the end of 2017, proved reserves had not been recognized for this project.

Norway The company holds a 20 percent nonoperated working interest in exploration Block PL 859, located in the Barents Sea. An exploration well was drilled in 2017, which resulted in noncommercial quantities of gas. A second well is scheduled for 2018 to further evaluate the potential of the license.

Sales of Natural Gas and Natural Gas Liquids

The company sells natural gas and natural gas liquids (NGLs) from its producing operations under a variety of contractual arrangements. In addition, the company also makes third-party purchases and sales of natural gas and NGLs in connection with its supply and trading activities.

During 2017, U.S. and international sales of natural gas averaged 3.3 billion and 5.1 billion cubic feet per day, respectively, which includes the company’s share of equity affiliates’ sales. Outside the United States, substantially all of the natural gas sales from the company’s producing interests are from operations in Angola, Australia, Bangladesh, Europe, Kazakhstan, Indonesia, Latin America, Myanmar, Nigeria, the Philippines and Thailand.

U.S. and international sales of NGLs averaged 139,000 and 93,000 barrels per day, respectively, in 2017. Substantially all of the international sales of NGLs from the company's producing interests are from operations in Angola, Australia, Canada, Indonesia, Nigeria and the United Kingdom.

Refer to “Selected Operating Data,” on page 39 in Management’s Discussion and Analysis of Financial Condition and Results of Operations, for further information on the company’s sales volumes of natural gas and natural gas liquids. Refer also to “Delivery Commitments” beginning on page 6 for information related to the company’s delivery commitments for the sale of crude oil and natural gas.

Downstream

Refining Operations

At the end of 2017, the company had a refining network capable of processing nearly 1.7 million barrels of crude oil per day. Operable capacity at December 31, 2017, and daily refinery inputs for 2015 through 2017 for the company and affiliate refineries are summarized in the table on the next page.

Average crude oil distillation capacity utilization during 2017 was 93 percent, compared with 92 percent in 2016. At the U.S. refineries, crude oil distillation capacity utilization averaged 98 percent in 2017, compared with 93 percent in 2016. Chevron processes both imported and domestic crude oil in its U.S. refining operations. Imported crude oil accounted for about 71 percent and 76 percent of Chevron’s U.S. refinery inputs in 2017 and 2016, respectively.

In the United States, the company continued work on projects to improve refinery flexibility and reliability. At the Richmond, California, refinery, the modernization project continued to progress, with start-up of the new hydrogen plant scheduled for second-half 2018, and full operation of the project expected in 2019. At the Salt Lake City, Utah, refinery, construction began for the alkylation retrofit project in July 2017. Project start-up is expected in 2020.

Outside the United States, the Singapore Refining Company (SRC), Chevron's 50 percent-owned joint venture, completed construction of gasoline clean fuels facilities and a cogeneration plant. The two trains at the cogeneration plant were commissioned in first-half 2017, enabling SRC to generate its own electricity and steam supply, improve energy efficiency, and significantly reduce greenhouse gas and sulfur oxide emissions. The gasoline clean fuels facilities enable SRC to produce higher-value gasoline that meets stricter emission standards.

The company completed the sale of its refining assets in British Columbia, Canada, in September 2017. In addition, the company signed an agreement for the sale of its interests in the Cape Town Refinery in South Africa in 2017. The sale is expected to close in 2018, pending local government approval.

Petroleum Refineries: Locations, Capacities and Inputs



Capacities and inputs in thousands of barrels per day		December 31, 2017		Refinery Inputs
Locations		Number	Operable Capacity	2017	2016	2015
Pascagoula	Mississippi	1	340	349	355	322
El Segundo	California	1	269	251	267	258
Richmond	California	1	257	248	188	245
Kapolei¹	Hawaii	—	—	—	37	47
Salt Lake City	Utah	1	53	53	53	52
Total Consolidated Companies — United States		4	919	901	900	924
Map Ta Phut	Thailand	1	165	152	162	164
Cape Town²	South Africa	1	110	68	78	69
Burnaby, B.C.³	Canada	—	—	40	51	46
Total Consolidated Companies — International		2	275	260	291	279
Affiliates	Various Locations	3	544	500	497	499
Total Including Affiliates — International		5	819	760	788	778
Total Including Affiliates — Worldwide		9	1,738	1,661	1,688	1,702


¹	In November 2016, the company sold the Hawaii Refinery.


²	Chevron holds a 75 percent controlling interest in the shares issued by Chevron South Africa (Pty) Limited, which owns the Cape Town Refinery. A consortium of South African partners, along with the employees of Chevron South Africa (Pty) Limited, own the remaining 25 percent.


³	In September 2017, the company sold the Burnaby, B.C. refinery.

Marketing Operations

The company markets petroleum products under the principal brands of “Chevron,” “Texaco” and “Caltex” throughout many parts of the world. The following table identifies the company’s and affiliates’ refined products sales volumes, excluding intercompany sales, for the three years ended December 31, 2017.

Refined Products Sales Volumes



Thousands of barrels per day	2017	2016	2015
United States
Gasoline	625	631	621
Jet Fuel	242	242	232
Diesel/Gas Oil	179	182	215
Residual Fuel Oil	48	59	59
Other Petroleum Products¹	103	99	101
Total United States	1,197	1,213	1,228
International²
Gasoline	365	382	389
Jet Fuel	274	261	271
Diesel/Gas Oil	490	468	478
Residual Fuel Oil	162	144	159
Other Petroleum Products¹	202	207	210
Total International	1,493	1,462	1,507
Total Worldwide²	2,690	2,675	2,735
¹ Principally naphtha, lubricants, asphalt and coke.
² Includes share of affiliates’ sales:	366	377	420

In the United States, the company markets under the Chevron and Texaco brands. At year-end 2017, the company supplied directly or through retailers and marketers approximately 7,700 Chevron- and Texaco-branded motor vehicle service stations, primarily in the southern and western states. Approximately 320 of these outlets are company-owned or -leased stations.

Outside the United States, Chevron supplied directly or through retailers and marketers approximately 5,800 branded service stations, including affiliates. The company markets in Latin America using the Texaco brand. In the Asia-Pacific region, southern Africa and the Middle East, the company uses the Caltex brand. The company also operates through affiliates under various brand names. In South Korea, the company operates through its 50 percent-owned affiliate, GS Caltex. In 2017, the company opened Chevron branded stations in northwestern Mexico. In September 2017, the company completed the sale of its marketing assets in British Columbia and Alberta, Canada. The company also signed an agreement for the sale of its marketing and lubricants businesses in southern Africa in 2017. The sale is expected to close in 2018, pending local government approval.

Chevron markets commercial aviation fuel at approximately 100 airports worldwide. The company also markets an extensive line of lubricant and coolant products under the product names Havoline, Delo, Ursa, Meropa, Rando, Clarity and Taro in the United States and worldwide under the three brands: Chevron, Texaco and Caltex.

Chemicals Operations

Chevron Oronite Company develops, manufactures and markets performance additives for lubricating oils and fuels and conducts research and development for additive component and blended packages. At the end of 2017, the company manufactured, blended or conducted research at 10 locations around the world. In November 2017, the company commissioned a new carboxylate plant in Singapore. In 2017, design work continued for a planned manufacturing plant in Ningbo, China, with a final investment decision expected in 2018.

Chevron owns a 50 percent interest in its Chevron Phillips Chemical Company LLC (CPChem) affiliate. CPChem produces olefins, polyolefins and alpha olefins and is a supplier of aromatics and polyethylene pipe, in addition to participating in the specialty chemical and specialty plastics markets. At the end of 2017, CPChem owned or had joint-venture interests in 30 manufacturing facilities and two research and development centers around the world.

During 2017, construction activities were completed on the U.S. Gulf Coast Petrochemicals Project, which is expected to capitalize on advantaged feedstock sourced from shale resource development in North America. The project includes an ethane cracker with an annual design capacity of 1.5 million metric tons of ethylene located at the Cedar Bayou facility and two polyethylene units located in Old Ocean, Texas, with a combined annual design capacity of one million metric tons. Start-up of the polyethylene units was achieved in September 2017. Mechanical completion of the ethane cracker was achieved in December 2017, with commissioning activities continuing in first quarter 2018 and transition to full production expected during second quarter 2018.

Chevron also maintains a role in the petrochemical business through the operations of GS Caltex, a 50 percent-owned affiliate. GS Caltex manufactures aromatics, including benzene, toluene and xylene. These base chemicals are used to produce a range of products, including adhesives, plastics and textile fibers. GS Caltex also produces polypropylene, which is used to make automotive and home appliance parts, food packaging, laboratory equipment, and textiles.

Transportation

Pipelines Chevron owns and operates a network of crude oil, natural gas and product pipelines and other infrastructure assets in the United States. In addition, Chevron operates pipelines for its 50 percent-owned CPChem affiliate. The company also has direct and indirect interests in other U.S. and international pipelines.

Refer to pages 12 and 13 in the Upstream section for information on the West African Gas Pipeline, the Baku-Tbilisi-Ceyhan Pipeline, the Western Route Export Pipeline and the Caspian Pipeline Consortium.

Shipping The company's marine fleet includes both U.S.- and foreign-flagged vessels. The U.S.-flagged vessels are engaged primarily in transporting refined products in the coastal waters of the United States. The foreign-flagged vessels transport crude oil, LNG, refined products and feedstocks in support of the company's global Upstream and Downstream businesses.

All six of the new LNG carriers in support of the company's growing LNG portfolio are in service, with the final two delivered in 2017.

Other Businesses

Research and Technology Chevron's energy technology organization supports upstream and downstream businesses. The company conducts research, develops and qualifies technology, and provides technical services and competency development. The disciplines cover earth sciences, reservoir and production engineering, drilling and completions, facilities engineering, manufacturing, process technology, catalysis, technical computing and health, environment and safety.

Chevron's information technology organization integrates computing, telecommunications, data management, cybersecurity and network technology to provide a digital infrastructure to enable Chevron’s global operations and business processes.

Chevron's technology ventures company supports Chevron's upstream and downstream businesses by bridging the gap between business unit needs and emerging technology solutions developed externally in areas of emerging materials, water management, information technology, power systems and production enhancement.

Some of the investments the company makes in the areas described above are in new or unproven technologies and business processes, and ultimate technical or commercial successes are not certain. Refer to Note 27 beginning on page 89 for a summary of the company's research and development expenses.

Environmental Protection The company designs, operates and maintains its facilities to avoid potential spills or leaks and to minimize the impact of those that may occur. Chevron requires its facilities and operations to have operating standards and processes and emergency response plans that address all credible and significant risks identified through site-specific risk and impact assessments. Chevron also requires that sufficient resources be available to execute these plans. In the unlikely event that a major spill or leak occurs, Chevron also maintains a Worldwide Emergency Response Team comprised of employees who are trained in various aspects of emergency response, including post-incident remediation.

To complement the company’s capabilities, Chevron maintains active membership in international oil spill response cooperatives, including the Marine Spill Response Corporation, which operates in U.S. territorial waters, and Oil Spill Response, Ltd., which operates globally. The company is a founding member of the Marine Well Containment Company, whose primary mission is to expediently deploy containment equipment and systems to capture and contain crude oil in the unlikely event of a future loss of control of a deepwater well in the Gulf of Mexico. In addition, the company is a member of the Subsea Well Response Project, which has the objective to further develop the industry’s capability to contain and shut in subsea well control incidents in different regions of the world.

The company is committed to improving energy efficiency in its day-to-day operations and is required to comply with the greenhouse gas-related laws and regulations to which it is subject. Refer to Item 1A. Risk Factors on pages 19 through 22 for further discussion of greenhouse gas regulation and climate change and the associated risks to Chevron’s business.

Refer to Management's Discussion and Analysis of Financial Condition and Results of Operations on page 45 for additional information on environmental matters and their impact on Chevron, and on the company's 2017 environmental expenditures. Refer to page 45 and Note 25 on page 88 for a discussion of environmental remediation provisions and year-end reserves.

Item 1A. Risk Factors

Chevron is a global energy company and its operating and financial results are subject to a variety of risks inherent in the global oil, gas, and petrochemical businesses. Many of these risks are not within the company's control and could materially impact the company’s results of operations and financial condition.

Chevron is exposed to the effects of changing commodity prices Chevron is primarily in a commodities business that has a history of price volatility. The single largest variable that affects the company’s results of operations is the price of crude oil, which can be influenced by general economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions that might be imposed by the Organization of Petroleum Exporting Countries (OPEC) or other producers, weather-related damage and disruptions, competing fuel prices, and geopolitical risks. Chevron evaluates the risk of changing commodity prices as part of its business planning process. An investment in the company carries significant exposure to fluctuations in global crude oil prices.

Extended periods of low prices for crude oil can have a material adverse impact on the company's results of operations, financial condition and liquidity. Among other things, the company’s upstream earnings, cash flows, and capital and exploratory expenditure programs could be negatively affected, as could its production and proved reserves. Upstream assets may also become impaired. Downstream earnings could be negatively affected because they depend upon the supply and demand for refined products and the associated margins on refined product sales. A significant or sustained decline in liquidity could adversely affect the company’s credit ratings, potentially increase financing costs and reduce access to debt markets. The company may be unable to realize anticipated cost savings, expenditure reductions and asset sales that are intended to compensate for such downturns. In some cases, liabilities associated with divested assets may return to the company when an acquirer of those assets subsequently declares bankruptcy. In addition, extended periods of low commodity prices can have a material adverse impact on the results of operations, financial condition and liquidity of the company’s suppliers, vendors, partners and equity affiliates upon which the company’s own results of operations and financial condition depends.

The scope of Chevron’s business will decline if the company does not successfully develop resources The company is in an extractive business; therefore, if it is not successful in replacing the crude oil and natural gas it produces with good prospects for future organic opportunities or through acquisitions, the company’s business will decline. Creating and maintaining an inventory of projects depends on many factors, including obtaining and renewing rights to explore, develop and produce hydrocarbons; drilling success; reservoir optimization; ability to bring long-lead-time, capital-intensive projects to completion on budget and on schedule; and efficient and profitable operation of mature properties.

The company’s operations could be disrupted by natural or human causes beyond its control Chevron operates in both urban areas and remote and sometimes inhospitable regions. The company’s operations are therefore subject to disruption from natural or human causes beyond its control, including physical risks from hurricanes, severe storms, floods and other

forms of severe weather, war, accidents, civil unrest, political events, fires, earthquakes, system failures, cyber threats and terrorist acts, any of which could result in suspension of operations or harm to people or the natural environment.

Chevron's risk management systems are designed to assess potential physical and other risks to its operations and assets and to plan for their resiliency. While capital investment reviews and decisions incorporate potential ranges of physical risks such as storm severity and frequency, sea level rise, air and water temperature, precipitation, fresh water access, wind speed, and earthquake severity, among other factors, it is difficult to predict with certainty the timing, frequency or severity of such events, any of which could have a material adverse effect on the company's results of operations or financial condition.

Cyberattacks targeting Chevron’s process control networks or other digital infrastructure could have a material adverse impact on the company’s business and results of operations There are numerous and evolving risks to cybersecurity and privacy from cyber threat actors, including criminal hackers, state-sponsored intrusions, industrial espionage and employee malfeasance. These cyber threat actors are becoming more sophisticated and coordinated in their attempts to access the company’s information technology (IT) systems and data, including the IT systems of cloud providers and third parties with which the company conducts business. Although Chevron devotes significant resources to prevent unwanted intrusions and to protect its systems and data, whether such data is housed internally or by external third parties, the company has experienced and will continue to experience cyber incidents of varying degrees in the conduct of its business. Cyber threat actors could compromise the company’s process control networks or other critical systems and infrastructure, resulting in disruptions to its business operations, injury to people, harm to the environment or its assets, access to its financial reporting systems, or loss, misuse or corruption of its critical data and proprietary information, including without limitation its intellectual property and business information and that of its employees, customers, partners and other third parties. Further, the company has exposure to cyber incidents and the negative impacts of such incidents related to its critical data and proprietary information housed on third-party IT systems, including the cloud. The company has limited control and visibility over such third-party IT systems. Cyber events could result in significant financial losses, legal or regulatory violations, reputational harm, and legal liability and could ultimately have a material adverse effect on the company’s business and results of operations.

The company’s operations have inherent risks and hazards that require significant and continuous oversight Chevron’s results depend on its ability to identify and mitigate the risks and hazards inherent to operating in the crude oil and natural gas industry. The company seeks to minimize these operational risks by carefully designing and building its facilities and conducting its operations in a safe and reliable manner. However, failure to manage these risks effectively could impair our ability to operate and result in unexpected incidents, including releases, explosions or mechanical failures resulting in personal injury, loss of life, environmental damage, loss of revenues, legal liability and/or disruption to operations. Chevron has implemented and maintains a system of corporate policies, processes and systems, behaviors and compliance mechanisms to manage safety, health, environmental, reliability and efficiency risks; to verify compliance with applicable laws and policies; and to respond to and learn from unexpected incidents. In certain situations where Chevron is not the operator, the company may have limited influence and control over third parties, which may limit its ability to manage and control such risks.

Chevron’s business subjects the company to liability risks from litigation or government action The company produces, transports, refines and markets potentially hazardous materials, and it purchases, handles and disposes of other potentially hazardous materials in the course of its business. Chevron's operations also produce byproducts, which may be considered pollutants. Often these operations are conducted through joint ventures over which the company may have limited influence and control. Any of these activities could result in liability or significant delays in operations arising from private litigation or government action, either as a result of an accidental, unlawful discharge or as a result of new conclusions about the effects of the company’s operations on human health or the environment. In addition, to the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to the company’s causation of or contribution to the asserted damage, or to other mitigating factors.

For information concerning some of the litigation in which the company is involved, see Note 17 to the Consolidated Financial Statements, beginning on page 71.

The company does not insure against all potential losses, which could result in significant financial exposure The company does not have commercial insurance or third-party indemnities to fully cover all operational risks or potential liability in the event of a significant incident or series of incidents causing catastrophic loss. As a result, the company is, to a substantial extent, self-insured for such events. The company relies on existing liquidity, financial resources and borrowing capacity to meet short-term obligations that would arise from such an event or series of events. The occurrence of a significant incident or unforeseen liability for which the company is not fully insured or for which insurance recovery is significantly delayed could have a material adverse effect on the company’s results of operations or financial condition.

Political instability and significant changes in the legal and regulatory environment could harm Chevron’s business The company’s operations, particularly exploration and production, can be affected by changing economic, regulatory and political environments in the various countries in which it operates. As has occurred in the past, actions could be taken by governments to increase public ownership of the company’s partially or wholly owned businesses or to impose additional taxes or royalties. In certain locations, governments have proposed or imposed restrictions on the company’s operations, export and exchange controls, burdensome taxes, and public disclosure requirements that might harm the company’s competitiveness or relations with other governments or third parties. In other countries, political conditions have existed that may threaten the safety of employees and the company’s continued presence in those countries, and internal unrest, acts of violence or strained relations between a government and the company or other governments may adversely affect the company’s operations. Those developments have, at times, significantly affected the company’s operations and results and are carefully considered by management when evaluating the level of current and future activity in such countries. Further, Chevron is required to comply with U.S. sanctions laws and regulations which, depending upon their scope, could adversely impact the company's operations in certain countries. In addition, changes in national, state or local environmental regulations or laws, including those designed to stop or impede the development or production of oil and gas, such as those related to the use of hydraulic fracturing or bans on drilling, could adversely affect the company's current or anticipated future operations and profitability.

Regulation of greenhouse gas (GHG) emissions could increase Chevron’s operational costs and reduce demand for Chevron’s hydrocarbon and other products In the years ahead, companies in the energy industry, like Chevron, may be challenged by an increase in international and domestic regulation relating to GHG emissions. Like any significant changes in the regulatory environment, GHG regulation could have the impact of curtailing profitability in the oil and gas sector or rendering the extraction of the company’s oil and gas resources economically infeasible. Although the IEA’s World Energy Outlook scenarios anticipate oil and gas continuing to make up a significant portion of the global energy mix through 2040 and beyond given their respective advantages in transportation and power generation, if a new onset of regulation contributes to a decline in the demand for the company’s products, this could have a material adverse effect on the company and its financial condition.

International agreements and national, regional and state legislation (e.g., California AB32, SB32 and AB398) and regulatory measures that aim to limit or reduce GHG emissions are currently in various stages of implementation. For example, the Paris Agreement went into effect in November 2016, and a number of countries are studying and adopting policies to meet their Paris Agreement goals. In some jurisdictions, the company is already subject to currently implemented programs such as the U.S. Renewable Fuel Standard program, the European Union Emissions Trading System, and the California cap-and-trade program and related low carbon fuel standard obligations. Other jurisdictions are considering adopting or are in the process of implementing laws or regulations to directly regulate GHG emissions through similar or other mechanisms such as, for example, via a carbon tax (e.g., Singapore and Canada) or via a cap-and-trade program (e.g., Mexico and China). The landscape continues to be in a state of constant re-assessment and legal challenge with respect to these laws and regulations, making it difficult to predict with certainty the ultimate impact they will have on the company in the aggregate.

GHG emissions-related laws and related regulations and the effects of operating in a potentially carbon-constrained environment may result in increased and substantial capital, compliance, operating and maintenance costs and could, among other things, reduce demand for hydrocarbons and the company’s hydrocarbon-based products, make the company’s products more expensive, adversely affect the economic feasibility of the company’s resources, and adversely affect the company’s sales volumes, revenues and margins. GHG emissions (e.g., carbon dioxide and methane) that could be regulated include, among others, those associated with the company’s exploration and production of hydrocarbons such as crude oil and natural gas; the upgrading of production from oil sands into synthetic oil; power generation; the conversion of crude oil and natural gas into refined hydrocarbon products; the processing, liquefaction and regasification of natural gas; the transportation of crude oil, natural gas and related products and consumers’ or customers’ use of the company’s hydrocarbon products. Many of these activities, such as consumers’ and customers’ use of the company’s products, as well as actions taken by the company’s competitors in response to such laws and regulations, are beyond the company’s control. In addition, increasing attention to climate change risks has resulted in an increased possibility of governmental investigations and additional private litigation against the company.

Consideration of GHG issues and the responses to those issues through international agreements and national, regional or state legislation or regulations are integrated into the company’s strategy and planning, capital investment reviews, and risk management tools and processes, where applicable. They are also factored into the company’s long-range supply, demand and energy price forecasts. These forecasts reflect long-range effects from renewable fuel penetration, energy efficiency standards, climate-related policy actions, and demand response to oil and natural gas prices. Additionally, the company assesses carbon pricing risks by considering carbon costs in these forecasts. The actual level of expenditure required to comply with new or potential climate change-related laws and regulations and amount of additional investments in new or

existing technology or facilities, such as carbon dioxide injection, is difficult to predict with certainty and is expected to vary depending on the actual laws and regulations enacted in a jurisdiction, the company’s activities in it and market conditions.

The ultimate effect of international agreements and national, regional and state legislation and regulatory measures to limit GHG emissions on the company’s financial performance, and the timing of these effects, will depend on a number of factors. Such factors include, among others, the sectors covered, the greenhouse gas emissions reductions required, the extent to which Chevron would be entitled to receive emission allowance allocations or would need to purchase compliance instruments on the open market or through auctions, the price and availability of emission allowances and credits, and the extent to which the company is able to recover the costs incurred through the pricing of the company’s products in the competitive marketplace. Further, the ultimate impact of GHG emissions-related agreements, legislation and measures on the company’s financial performance is highly uncertain because the company is unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes.

Changes in management’s estimates and assumptions may have a material impact on the company’s consolidated financial statements and financial or operational performance in any given period In preparing the company’s periodic reports under the Securities Exchange Act of 1934, including its financial statements, Chevron’s management is required under applicable rules and regulations to make estimates and assumptions as of a specified date. These estimates and assumptions are based on management’s best estimates and experience as of that date and are subject to substantial risk and uncertainty. Materially different results may occur as circumstances change and additional information becomes known. Areas requiring significant estimates and assumptions by management include impairments to property, plant and equipment; estimates of crude oil and natural gas recoverable reserves; accruals for estimated liabilities, including litigation reserves; and measurement of benefit obligations for pension and other postretirement benefit plans. Changes in estimates or assumptions or the information underlying the assumptions, such as changes in the company’s business plans, general market conditions or changes in commodity prices, could affect reported amounts of assets, liabilities or expenses.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

The location and character of the company’s crude oil and natural gas properties and its refining, marketing, transportation and chemicals facilities are described on page 3 under Item 1. Business. Information required by Subpart 1200 of Regulation S-K (“Disclosure by Registrants Engaged in Oil and Gas Producing Activities”) is also contained in Item 1 and in Tables I through VII on pages 91 through 101. Note 24, “Properties, Plant and Equipment,” to the company’s financial statements is on page 87.

Item 3. Legal Proceedings

Governmental Proceedings Chevron facilities within the jurisdiction of California’s South Coast Air Quality Management District (SCAQMD) currently have multiple outstanding Notices of Violation (NOVs) issued by SCAQMD. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more. In addition, as initially disclosed in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2016, in April 2016, Chevron received a proposal from the SCAQMD seeking to collectively resolve certain NOVs issued in 2012 and 2013 to Chevron’s El Segundo Refinery. Subsequently, the SCAQMD provided notice to Chevron that it was also seeking to resolve certain NOVs issued to the refinery in 2014. In December 2017, Chevron and the SCAQMD entered into a settlement agreement to resolve allegations in six NOVs for a civil penalty of $375,500. In January 2018, Chevron and the SCAQMD entered into a settlement agreement to resolve allegations associated with the remaining three NOVs for a civil penalty of $5,137,250.

As initially disclosed in the Annual Report on Form 10-K for the year ended December 31, 2013, on August 6, 2012, a piping failure and fire occurred at the Chevron refinery in Richmond, California. The United States Environmental Protection Agency (EPA) issued alleged findings of violation related to the incident on December 17, 2013, pursuant to its authority under the Clean Air Act Risk Management Plan program (RMP). Following the Richmond incident, EPA also conducted RMP inspections at Chevron’s El Segundo, California; Pascagoula, Mississippi; Kapolei, Hawaii; and Salt Lake City, Utah refineries. With the participation of the United States Department of Justice, Chevron and EPA are negotiating a potential combined resolution that may include all of EPA’s alleged findings of violation related to the Richmond incident and subsequent RMP inspections. Resolution of those alleged findings of violation may result in the payment of a civil penalty of $100,000 or more.

As initially disclosed in the Annual Report on Form 10-K for the year ended December 31, 2016, on December 5, 2016, Chevron received a NOV from the California Air Resources Board (CARB) alleging that for compliance years 2011-2015, Chevron failed to deduct some exported volumes of fuel from the sales that must be reported under the state’s Low Carbon

Fuel Standard (LCFS) program. The allegation is that Chevron purchased and retired more LCFS credits than were required. Chevron and CARB are negotiating a potential resolution of the alleged violation. Resolution of this NOV may result in the payment of a civil penalty of $100,000 or more.

As initially disclosed in the Quarterly Report on Form 10-Q for the quarter ended March 31, 2017, on November 18, 2016, Chevron received an Administrative Order (AO) from the EPA alleging noncompliance with the water permit that governed conveyances of captured groundwater and spring water from the former Questa mine located in New Mexico to its associated tailing facility. Chevron is concluding its negotiations with EPA regarding this matter.

As initially disclosed in the Quarterly Report on Form 10-Q for the quarter ended September 30, 2017, on August 3, 2017, Chevron received a Notice of Intent to File an Administrative Complaint from the EPA in connection with certain waste matters at the Kapolei, Hawaii refinery during the period of time that the facility was owned and operated by Chevron. Chevron is evaluating the allegations stated in the Notice. Resolution of these matters may result in the payment of a civil penalty of $100,000 or more.

Chevron facilities within the jurisdiction of California’s Bay Area Air Quality Management District (BAAQMD) currently have multiple outstanding NOVs issued by BAAQMD. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more. On October 26, 2017, Chevron received a proposal from the BAAQMD seeking to resolve certain NOVs related to violations that occurred at Chevron’s Richmond Refinery and Avon, California terminal in 2015. Resolution of the alleged violations may result in the payment of a civil penalty of $100,000 or more.

Other Proceedings Information related to other legal proceedings is included beginning on page 71 in Note 17 to the Consolidated Financial Statements.

Item 4. Mine Safety Disclosures

Not applicable.

PART II

Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

The information on Chevron’s common stock market prices, dividends, principal exchanges on which the stock is traded and number of stockholders of record is contained in the Quarterly Results and Stock Market Data tabulations on page 49.

Chevron Corporation Issuer Purchases of Equity Securities for Quarter Ended December 31, 2017



	Total Number	Average		Total Number of Shares	Maximum Number of Shares
	of Shares	Price Paid		Purchased as Part of Publicly	That May Yet be Purchased
Period	Purchased^1,2	per Share		Announced Program	Under the Program²
Oct. 1 – Oct. 31, 2017	312		$117.42	—	—
Nov. 1 – Nov. 30, 2017	—			—	—
Dec. 1 – Dec. 31, 2017	—			—	—
Total Oct. 1 – Dec. 31, 2017	312		$117.42	—	—


¹	Includes common shares repurchased from company employees and directors for required personal income tax withholdings on the exercise of the stock options and shares delivered or attested to in satisfaction of the exercise price by holders of the employee and director stock options. The options were issued to and exercised by management under Chevron long-term incentive plans.

In July 2010, the Board of Directors approved an ongoing share repurchase program with no set term or monetary limits, under which common shares would be acquired by the company through open market purchases or in negotiated transactions at prevailing prices, as permitted by securities laws and other legal requirements and subject to market conditions and other factors. From inception of the program through 2014, the company had purchased 180,886,291 shares under this program (some pursuant to a Rule 10b5-1 plan and some pursuant to accelerated share repurchase plans) for $20 billion at an average price of approximately $111 per share. The company did not acquire any shares under the program in 2015, 2016 or 2017.

Item 6. Selected Financial Data

The selected financial data for years 2013 through 2017 are presented on page 90.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The index to Management’s Discussion and Analysis of Financial Condition and Results of Operations, Consolidated Financial Statements and Supplementary Data is presented on page 29.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

The company’s discussion of interest rate, foreign currency and commodity price market risk is contained in Management’s Discussion and Analysis of Financial Condition and Results of Operations — “Financial and Derivative Instrument Market Risk,” on page 43 and in Note 11 to the Consolidated Financial Statements, “Financial and Derivative Instruments,” beginning on page 65.

Item 8. Financial Statements and Supplementary Data

The index to Management’s Discussion and Analysis, Consolidated Financial Statements and Supplementary Data is presented on page 29.

Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

(a) Evaluation of Disclosure Controls and Procedures The company’s management has evaluated, with the participation of the Chief Executive Officer and the Chief Financial Officer, the effectiveness of the company’s disclosure controls and procedures (as defined in Rule 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934 (the “Exchange Act”)) as of the end of the period covered by this report. Based on this evaluation, management concluded that the company’s disclosure controls and procedures were effective as of December 31, 2017.

(b) Management’s Report on Internal Control Over Financial Reporting The company’s management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The company’s management, including the Chief Executive Officer and the Chief Financial Officer, conducted an evaluation of the effectiveness of the company’s internal control over financial reporting based on the Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on the results of this evaluation, the company’s management concluded that internal control over financial reporting was effective as of December 31, 2017.

The effectiveness of the company’s internal control over financial reporting as of December 31, 2017, has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in its report included on page 51.

(c) Changes in Internal Control Over Financial Reporting During the quarter ended December 31, 2017, there were no changes in the company’s internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the company’s internal control over financial reporting.

Item 9B. Other Information

Rule 10b5-1 Plan Elections

R. Hewitt Pate, Vice President and General Counsel, entered into a pre-arranged stock trading plan in November 2017. Mr. Pate’s plan provides for the potential exercise of vested stock options and the associated sale of up to 51,000 shares of Chevron common stock between February 2018 and November 2018.

This trading plan was entered into during an open insider trading window and is intended to satisfy Rule 10b5-1(c) of the Securities Exchange Act of 1934, as amended, and Chevron’s policies regarding transactions in Chevron securities.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Executive Officers of the Registrant at February 22, 2018

Members of the Corporation's Executive Committee are the Executive Officers of the Corporation:



Name	Age	Current and Prior Positions (up to five years)	Current Areas of Responsibility
M.K. Wirth	57	Chairman of the Board and Chief Executive Officer (since February 2018) Vice Chairman of the Board and Executive Vice President, Midstream and Development (February 2017 to January 2018) Executive Vice President, Midstream and Development (February 2016 through January 2017) Executive Vice President, Downstream (2006 through 2015)	Chairman of the Board and Chief Executive Officer
J.W. Johnson	58	Executive Vice President, Upstream (since 2015) Senior Vice President, Upstream (2014) President, Europe, Eurasia and Middle East Exploration and Production (2011 through 2013)	Worldwide Exploration and Production Activities
P.R. Breber	53	Executive Vice President, Downstream (since 2016) Corporate Vice President and President, Gas and Midstream (2014 through 2015) Managing Director, Asia South Business Unit (2012 through 2013)	Worldwide Refining, Marketing and Lubricants; Chemicals
J.C. Geagea	58	Executive Vice President, Technology, Projects and Services (since 2015) Senior Vice President, Technology, Projects and Services (2014) Corporate Vice President and President, Gas and Midstream (2012 through 2013)	Technology; Health, Environment and Safety; Project Resources Company; Procurement
M.A. Nelson	54	Vice President, Midstream, Strategy and Policy (since February 2018) Vice President, Strategic Planning (May 2016 through January 2018) President, International Products (2010 through April 2016)	Corporate Strategy; Policy, Government and Public Affairs; Supply and Trading Activities; Shipping; Pipeline; Power and Energy Management
P.E. Yarrington	61	Vice President and Chief Financial Officer (since 2009)	Finance
R.H. Pate	55	Vice President and General Counsel (since 2009)	Law, Governance and Compliance

The information about directors required by Item 401 (a), (d), (e) and (f) of Regulation S-K and contained under the heading “Election of Directors” in the Notice of the 2018 Annual Meeting of Stockholders and 2018 Proxy Statement, to be filed pursuant to Rule 14a-6(b) under the Securities Exchange Act of 1934 (the “Exchange Act”), in connection with the company’s 2018 Annual Meeting (the “2018 Proxy Statement”), is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 405 of Regulation S-K and contained under the heading “Stock Ownership Information — Section 16(a) Beneficial Ownership Reporting Compliance” in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 406 of Regulation S-K and contained under the heading “Corporate Governance — Business Conduct and Ethics Code” in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(d)(4) and (5) of Regulation S-K and contained under the heading “Corporate Governance — Board Committees” in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 11. Executive Compensation

The information required by Item 402 of Regulation S-K and contained under the headings “Executive Compensation” and “Director Compensation” in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(e)(4) of Regulation S-K and contained under the heading “Corporate Governance — Board Committees” in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(e)(5) of Regulation S-K and contained under the heading “Corporate Governance — Management Compensation Committee Report” in the 2018 Proxy Statement is incorporated herein by reference into this Annual Report on Form 10-K. Pursuant to the rules and regulations of the SEC under the Exchange Act, the information under such caption incorporated by reference from the 2018 Proxy Statement shall not be deemed to be “soliciting material,” or to be “filed” with the Commission, or subject to Regulation 14A or 14C or the liabilities of Section 18 of the Exchange Act, nor shall it be deemed incorporated by reference into any filing under the Securities Act of 1933.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information required by Item 403 of Regulation S-K and contained under the heading “Stock Ownership Information — Security Ownership of Certain Beneficial Owners and Management” in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 201(d) of Regulation S-K and contained under the heading “Equity Compensation Plan Information” in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information required by Item 404 of Regulation S-K and contained under the heading “Corporate Governance — Related Person Transactions” in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

The information required by Item 407(a) of Regulation S-K and contained under the heading “Corporate Governance — Director Independence” in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

Item 14. Principal Accounting Fees and Services

The information required by Item 9(e) of Schedule 14A and contained under the heading “Board Proposal to Ratify PricewaterhouseCoopers LLP as the Independent Registered Public Accounting Firm for 2018" in the 2018 Proxy Statement is incorporated by reference into this Annual Report on Form 10-K.

THIS PAGE INTENTIONALLY LEFT BLANK

Financial Table of Contents






	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	Key Financial Results	30
	Earnings by Major Operating Area	30
	Business Environment and Outlook	30
	Operating Developments	34
	Results of Operations	34
	Consolidated Statement of Income	37
	Selected Operating Data	39
	Liquidity and Capital Resources	40
	Financial Ratios	42
	Off-Balance-Sheet Arrangements, Contractual Obligations, Guarantees and Other Contingencies	42
	Financial and Derivative Instrument Market Risk	43
	Transactions With Related Parties	44
	Litigation and Other Contingencies	44
	Environmental Matters	45
	Critical Accounting Estimates and Assumptions	45
	New Accounting Standards	48
	Quarterly Results and Stock Market Data	49





	Consolidated Financial Statements
	Reports of Management	50
	Report of Independent Registered Public Accounting Firm	51
	Consolidated Statement of Income	52
	Consolidated Statement of Comprehensive Income	53
	Consolidated Balance Sheet	54
	Consolidated Statement of Cash Flows	55
	Consolidated Statement of Equity	56






Notes to the Consolidated Financial Statements
Note 1	Summary of Significant Accounting Policies	57
Note 2	Changes in Accumulated Other Comprehensive Losses	59
Note 3	Noncontrolling Interests	60
Note 4	Information Relating to the Consolidated Statement of Cash Flows	60
Note 5	New Accounting Standards	61
Note 6	Lease Commitments	62
Note 7	Summarized Financial Data – Chevron U.S.A. Inc.	63
Note 8	Summarized Financial Data – Tengizchevroil LLP	63
Note 9	Summarized Financial Data - Chevron Phillips Chemical Company LLC	64
Note 10	Fair Value Measurements	64
Note 11	Financial and Derivative Instruments	65
Note 12	Assets Held for Sale	66
Note 13	Equity	66
Note 14	Earnings Per Share	67
Note 15	Operating Segments and Geographic Data	67
Note 16	Investments and Advances	70
Note 17	Litigation	71
Note 18	Taxes	75
Note 19	Short-Term Debt	78
Note 20	Long-Term Debt	79
Note 21	Accounting for Suspended Exploratory Wells	80
Note 22	Stock Options and Other Share-Based Compensation	81
Note 23	Employee Benefit Plans	82
Note 24	Properties, Plant and Equipment	87
Note 25	Other Contingencies and Commitments	87
Note 26	Asset Retirement Obligations	89
Note 27	Other Financial Information	89

Five-Year Financial Summary		90
Supplemental Information on Oil and Gas Producing Activities		91

Management's Discussion and Analysis of Financial Condition and Results of Operations

Key Financial Results



Millions of dollars, except per-share amounts	2017			2016			2015
Net Income (Loss) Attributable to Chevron Corporation	$	9,195		$	(497	)	$	4,587
Per Share Amounts:
Net Income (Loss) Attributable to Chevron Corporation
– Basic	$	4.88		$	(0.27	)	$	2.46
– Diluted	$	4.85		$	(0.27	)	$	2.45
Dividends	$	4.32		$	4.29		$	4.28
Sales and Other Operating Revenues	$	134,674		$	110,215		$	129,925
Return on:
Capital Employed	5.0		%	(0.1		)%	2.5		%
Stockholders’ Equity	6.3		%	(0.3		)%	3.0		%
Earnings by Major Operating Area
Millions of dollars	2017			2016			2015
Upstream
United States	$	3,640		$	(2,054	)	$	(4,055	)
International	4,510			(483		)	2,094
Total Upstream	8,150			(2,537		)	(1,961		)
Downstream
United States	2,938			1,307			3,182
International	2,276			2,128			4,419
Total Downstream	5,214			3,435			7,601
All Other	(4,169		)	(1,395		)	(1,053		)
Net Income (Loss) Attributable to Chevron Corporation^1,2	$	9,195		$	(497	)	$	4,587
¹ Includes foreign currency effects:	$	(446	)	$	58		$	769
²Income net of tax, also referred to as “earnings” in the discussions that follow.

Refer to the “Results of Operations” section beginning on page 34 for a discussion of financial results by major operating area for the three years ended December 31, 2017.

Business Environment and Outlook

Chevron is a global energy company with substantial business activities in the following countries: Angola, Argentina, Australia, Azerbaijan, Bangladesh, Brazil, Canada, China, Colombia, Democratic Republic of the Congo, Denmark, Indonesia, Kazakhstan, Myanmar, Nigeria, the Partitioned Zone between Saudi Arabia and Kuwait, the Philippines, Republic of Congo, Singapore, South Africa, South Korea, Thailand, the United Kingdom, the United States, and Venezuela.

Earnings of the company depend mostly on the profitability of its upstream business segment. The biggest factor affecting the results of operations for the upstream segment is the price of crude oil. The price of crude oil has fallen significantly since mid-year 2014. The downturn in the price of crude oil has impacted the company's results of operations, cash flows, leverage, capital and exploratory investment program and production outlook. A sustained lower price environment could result in the impairment or write-off of specific assets in future periods. The company has responded with reductions in operating expenses, pacing and re-focusing of capital and exploratory expenditures, and increased asset sales. The company anticipates that crude oil prices will increase in the future, as continued growth in demand and a slowing in supply growth should bring global markets into balance; however, the timing of any such increase is unknown. In the company's downstream business, crude oil is the largest cost component of refined products. It is the company's objective to deliver competitive results and shareholder value in any business environment.

The effective tax rate for the company can change substantially during periods of significant earnings volatility. This is due to the mix effects that are impacted both by the absolute level of earnings or losses and whether they arise in higher or lower tax rate jurisdictions. As a result, a decline or increase in the effective income tax rate in one period may not be indicative of expected results in future periods. Note 18 provides the company’s effective income tax rate for the last three years.

Refer to the "Cautionary Statement Relevant to Forward-Looking Information" on page 2 and to "Risk Factors" in Part I, Item 1A, on pages 19 through 22 for a discussion of some of the inherent risks that could materially impact the company's results of operations or financial condition.

The company continually evaluates opportunities to dispose of assets that are not expected to provide sufficient long-term value or to acquire assets or operations complementary to its asset base to help augment the company’s financial

Management's Discussion and Analysis of Financial Condition and Results of Operations

performance and value growth. The company's asset sale program for 2016 and 2017 targeted before-tax proceeds of $5-10 billion. Proceeds and deposits related to asset sales were $2.8 billion in 2016 and $5.2 billion in 2017. Refer to the “Results of Operations” section beginning on page 34 for discussions of net gains on asset sales during 2017. Asset dispositions and restructurings may also occur in future periods and could result in significant gains or losses.

The company closely monitors developments in the financial and credit markets, the level of worldwide economic activity, and the implications for the company of movements in prices for crude oil and natural gas. Management takes these developments into account in the conduct of daily operations and for business planning.

Comments related to earnings trends for the company’s major business areas are as follows:

Upstream Earnings for the upstream segment are closely aligned with industry prices for crude oil and natural gas. Crude oil and natural gas prices are subject to external factors over which the company has no control, including product demand connected with global economic conditions, industry production and inventory levels, technology advancements, production quotas or other actions imposed by the Organization of Petroleum Exporting Countries (OPEC) or other producers, actions of regulators, weather-related damage and disruptions, competing fuel prices, and regional supply interruptions or fears thereof that may be caused by military conflicts, civil unrest or political uncertainty. Any of these factors could also inhibit the company’s production capacity in an affected region. The company closely monitors developments in the countries in which it operates and holds investments, and seeks to manage risks in operating its facilities and businesses. The longer-term trend in earnings for the upstream segment is also a function of other factors, including the company’s ability to find or acquire and efficiently produce crude oil and natural gas, changes in fiscal terms of contracts, and changes in tax laws and regulations.

The company continues to actively manage its schedule of work, contracting, procurement and supply-chain activities to effectively manage costs. However, price levels for capital and exploratory costs and operating expenses associated with the production of crude oil and natural gas can be subject to external factors beyond the company’s control including, among other things, the general level of inflation, commodity prices and prices charged by the industry’s material and service providers, which can be affected by the volatility of the industry’s own supply-and-demand conditions for such materials and services. Industry cost inflation in most onshore segments, including North America unconventionals, started to modestly rise in 2017 with increases in commodity prices and higher levels of activity and investment. Offshore costs continue to decline driven by lower offshore activity levels and increased competition among suppliers. Capital and exploratory expenditures and operating expenses could also be affected by damage to production facilities caused by severe weather or civil unrest, delays in construction, or other factors.

The chart above shows the trend in benchmark prices for Brent crude oil, West Texas Intermediate (WTI) crude oil and U.S. Henry Hub natural gas. The Brent price averaged $54 per barrel for the full-year 2017, compared to $44 in 2016. As of mid-February 2018, the Brent price was $62 per barrel. The majority of the company’s equity crude production is priced based on the Brent benchmark. Crude oil prices were better supported in 2017 amid firming demand, rising geopolitical tensions, and ongoing output reductions by OPEC and certain non-OPEC producers. However, upside was limited as rebounding U.S. and other non-OPEC production resulted in ongoing oversupplied conditions. Prices weakened gradually over the first half of 2017 due to concerns that OPEC cuts would be allowed to expire in June 2017, but firmed over the

Management's Discussion and Analysis of Financial Condition and Results of Operations

second half of 2017 after OPEC’s decision on May 25, 2017, to extend cuts through the first quarter of 2018. Price support was reinforced on November 30, 2017, when OPEC and their non-OPEC partners agreed to further extend output cuts through December 2018.

The WTI price averaged $51 per barrel for the full-year 2017, compared to $43 in 2016. As of mid-February 2018, the WTI price was $59 per barrel. WTI traded at a discount to Brent throughout 2017. After starting 2017 at a $2 discount to Brent, the WTI discount expanded to about $6 by year-end due to rising U.S. crude production, rebounding inventories, and growing concerns that pipeline infrastructure constraints would again restrict flows to export outlets on the Gulf Coast.

A differential in crude oil prices exists between high-gravity, low-sulfur crudes and low-gravity, high-sulfur crudes. The amount of the differential in any period is associated with the relative supply/demand balances for each crude type. In second-half 2017, the differential held generally steady in North America as robust refinery demand supported heavy crude values, while light sweet crude prices in the U.S. were supported by rising exports of domestic production. Outside of North America, differentials were steady to modestly wider amid well-supplied light sweet crude markets in the Atlantic Basin, while rising U.S. exports to Asia increased competitive pressure on Middle East exports to the region. Chevron has producing interests in heavy crude oil in California, Indonesia, the Partitioned Zone between Saudi Arabia and Kuwait, Venezuela and in certain fields in Angola, China and the United Kingdom sector of the North Sea. (See page 39 for the company’s average U.S. and international crude oil realizations.)

In contrast to price movements in the global market for crude oil, price changes for natural gas in many regional markets are more closely aligned with supply-and-demand conditions in those markets. Fluctuations in the price of natural gas in the United States are closely associated with customer demand relative to the volumes produced and stored in North America. In the United States, prices at Henry Hub averaged $2.97 per thousand cubic feet (MCF) during 2017, compared with $2.46 during 2016. As of mid-February 2018, the Henry Hub spot price was $2.57 per MCF.

Outside the United States, price changes for natural gas depend on a wide range of supply, demand and regulatory circumstances. Chevron sells natural gas into the domestic pipeline market in most locations. In some locations, Chevron has invested in long-term projects to produce and liquefy natural gas for transport by tanker to other markets. The company's long-term contract prices for liquefied natural gas (LNG) are typically linked to crude oil prices. Most of the equity LNG offtake from the operated Australian LNG projects is committed under binding long-term contracts, with the remainder to be sold in the Asian spot LNG market. The Asian spot market reflects the supply and demand for LNG in the Pacific Basin and is not directly linked to crude oil prices. International natural gas realizations averaged $4.62 per MCF during 2017, compared with $4.02 per MCF during 2016. (See page 39 for the company’s average natural gas realizations for the U.S. and international regions.)

The company’s worldwide net oil-equivalent production in 2017 averaged 2.728 million barrels per day. About one-sixth of the company’s net oil-equivalent production in 2017 occurred in the OPEC-member countries of Angola, Nigeria and Venezuela. OPEC quotas had no effect on the company’s net crude oil production in 2017 or 2016.

The company estimates that net oil-equivalent production in 2018 will grow 4 to 7 percent compared to 2017, assuming a Brent crude oil price of $60 per barrel and excluding the impact of anticipated 2018 asset sales. This estimate is subject to many factors and uncertainties, including quotas or other actions that may be imposed by OPEC; price effects on entitlement volumes; changes in fiscal terms or restrictions on the scope of company operations; delays in construction, start-up or ramp-up of projects; fluctuations in demand for natural gas in various markets; weather conditions that may shut in production; civil unrest; changing geopolitics; delays in completion of maintenance turnarounds; greater-than-expected declines in production from mature fields; or other disruptions to operations. The outlook for future production levels is also affected by the size and number of economic investment opportunities and, for new, large-scale projects, the time lag between initial exploration and the beginning of production. Investments in upstream projects generally begin well in advance of the start of the associated crude oil and natural gas production.

Management's Discussion and Analysis of Financial Condition and Results of Operations

In the Partitioned Zone between Saudi Arabia and Kuwait, production was shut-in beginning in May 2015 as a result of difficulties in securing work and equipment permits. Net oil-equivalent production in the Partitioned Zone in 2014 was 81,000 barrels per day. During 2015, net oil-equivalent production averaged 28,000 barrels per day. As of early 2018, production remains shut in and the exact timing of a production restart is uncertain and dependent on dispute resolution between Saudi Arabia and Kuwait. The financial effects from the loss of production in 2017 were not significant and are not expected to be significant in 2018.

Net proved reserves for consolidated companies and affiliated companies totaled 11.7 billion barrels of oil-equivalent at year-end 2017, an increase of 5 percent from year-end 2016. The reserve replacement ratio in 2017 was 155 percent. Refer to Table V beginning on page 95 for a tabulation of the company’s proved net oil and gas reserves by geographic area, at the beginning of 2015 and each year-end from 2015 through 2017, and an accompanying discussion of major changes to proved reserves by geographic area for the three-year period ending December 31, 2017.

Refer to the “Results of Operations” section on pages 34 through 37 for additional discussion of the company’s upstream business.

Downstream Earnings for the downstream segment are closely tied to margins on the refining, manufacturing and marketing of products that include gasoline, diesel, jet fuel, lubricants, fuel oil, fuel and lubricant additives, and petrochemicals. Industry margins are sometimes volatile and can be affected by the global and regional supply-and-demand balance for refined products and petrochemicals, and by changes in the price of crude oil, other refinery and petrochemical feedstocks, and natural gas. Industry margins can also be influenced by inventory levels, geopolitical events, costs of materials and services, refinery or chemical plant capacity utilization, maintenance programs, and disruptions at refineries or chemical plants resulting from unplanned outages due to severe weather, fires or other operational events.

Other factors affecting profitability for downstream operations include the reliability and efficiency of the company’s refining, marketing and petrochemical assets, the effectiveness of its crude oil and product supply functions, and the volatility of tanker-charter rates for the company’s shipping operations, which are driven by the industry’s demand for crude oil and product tankers. Other factors beyond the company’s control include the general level of inflation and energy costs to operate the company’s refining, marketing and petrochemical assets.

The company’s most significant marketing areas are the West Coast and Gulf Coast of the United States, Asia and southern Africa. Chevron operates or has significant ownership interests in refineries in each of these areas.

Refer to the “Results of Operations” section on pages 34 through 37 for additional discussion of the company’s downstream operations.

All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities and technology companies.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Operating Developments

Key operating developments and other events during 2017 and early 2018 included the following:

Upstream

Angola Commenced production from the main production facility of the Mafumeira Sul Project.

Australia Achieved start-up of Train 3 at the Gorgon LNG Project and Train 1 at the Wheatstone LNG Project.

Canada Achieved start-up of the Hebron Project.

Indonesia Completed the sale of the geothermal business.

United States Announced significant crude oil discoveries at the Whale and Ballymore prospects in the Gulf of Mexico.

Downstream

Canada Completed the sale of refining and marketing assets in British Columbia and Alberta.

United States The company’s 50 percent-owned affiliate, Chevron Phillips Chemical Company LLC achieved start-up of two polyethylene units and reached mechanical completion of a new ethane cracker at its U.S. Gulf Coast Petrochemicals Project in Texas.

Other

Common Stock Dividends The 2017 annual dividend was $4.32 per share, making 2017 the 30th consecutive year that the company increased its annual dividend payout. In January 2018, the company's Board of Directors approved a $0.04 per share increase in the quarterly dividend to $1.12 per share, payable in March 2018.

Results of Operations

The following section presents the results of operations and variances on an after-tax basis for the company’s business segments – Upstream and Downstream – as well as for “All Other.” Earnings are also presented for the U.S. and international geographic areas of the Upstream and Downstream business segments. Refer to Note 15, beginning on page 67, for a discussion of the company’s “reportable segments.” This section should also be read in conjunction with the discussion in “Business Environment and Outlook” on pages 30 through 33.

U.S. Upstream



Millions of dollars	2017		2016			2015
Earnings	$	3,640	$	(2,054	)	$	(4,055	)

U.S. upstream earnings were $3.64 billion in 2017, compared with a loss of $2.05 billion in 2016. The improvement in earnings reflected a benefit of $3.33 billion from U.S. tax reform, higher crude oil and natural gas realizations of $1.3 billion

Management's Discussion and Analysis of Financial Condition and Results of Operations

and lower depreciation expenses of $650 million, primarily reflecting a decrease in impairments and other asset write-offs. Lower operating expenses of $140 million also contributed to the improvement.

U.S. upstream operations incurred a loss of $2.05 billion in 2016, compared with a loss of $4.06 billion from 2015. The improvement was due to lower depreciation expense of $1.2 billion and lower exploration expense of $780 million primarily reflecting a decrease in impairments and project cancellations. Also contributing to the improvement were lower operating expenses of $600 million and lower tax items of $190 million. Partially offsetting these effects were lower crude oil and natural gas realizations of $920 million.

The company’s average realization for U.S. crude oil and natural gas liquids in 2017 was $44.53 per barrel, compared with $35.00 in 2016 and $42.70 in 2015. The average natural gas realization was $2.10 per thousand cubic feet in 2017, compared with $1.59 in 2016 and $1.92 in 2015.

Net oil-equivalent production in 2017 averaged 681,000 barrels per day, down 1 percent from 2016 and down 5 percent from 2015. Between 2017 and 2016, production increases from shale and tight properties in the Permian Basin in Texas and New Mexico and base business in the Gulf of Mexico were more than offset by the effect of asset sales of 59,000 barrels per day and normal field declines. Between 2016 and 2015, production increases from shale and tight properties in the Permian Basin in Texas and New Mexico, and base business were more than offset by the effect of asset sales and normal field declines.

The net liquids component of oil-equivalent production for 2017 averaged 519,000 barrels per day, up 3 percent from 2016 and 4 percent from 2015. Net natural gas production averaged about 970 million cubic feet per day in 2017, down 13 percent from 2016 and 26 percent from 2015, primarily as a result of asset sales. Refer to the “Selected Operating Data” table on page 39 for a three-year comparison of production volumes in the United States.

International Upstream



Millions of dollars	2017			2016			2015
Earnings^*	$	4,510		$	(483	)	$	2,094
^*Includes foreign currency effects:	$	(456	)	$	122		$	725

International upstream earnings were $4.51 billion in 2017, compared with a loss of $483 million in 2016. The increase in earnings was primarily due to higher crude oil realizations of $2.59 billion, higher natural gas sales volumes of $1.22 billion, higher gains on asset sales of $750 million, and lower operating expenses of $410 million. Foreign currency effects had an unfavorable impact on earnings of $578 million between periods.

International upstream incurred a loss of $483 million in 2016, compared with earnings of $2.09 billion in 2015. The decrease in earnings was primarily due to lower crude oil realizations of $1.89 billion, lower natural gas realizations of $600 million, lower gains on asset sales of $450 million and higher tax items of $330 million. Partially offsetting the decrease were lower exploration and operating expenses of $640 million and $520 million, respectively, and higher natural gas sales volumes of $330 million. Foreign currency effects had an unfavorable impact on earnings of $603 million between periods.

The company’s average realization for international crude oil and natural gas liquids in 2017 was $49.46 per barrel, compared with $38.61 in 2016 and $46.52 in 2015. The average natural gas realization was $4.62 per thousand cubic feet in 2017, compared with $4.02 and $4.53 in 2016 and 2015, respectively.

International net oil-equivalent production was 2.05 million barrels per day in 2017, up 8 percent from 2016 and 2015. Between 2017 and 2016, production increases from major capital projects and lower planned maintenance-related downtime were partially offset by production entitlement effects in several locations and normal field declines. Between 2016 and 2015, production increases from major capital projects, base business, and shale and tight properties were largely offset by normal field declines, the Partitioned Zone shut-in, the impact of civil unrest in Nigeria and planned turnaround activity.

The net liquids component of international oil-equivalent production was 1.20 million barrels per day in 2017, down 1 percent from 2016 and down 3 percent from 2015. International net natural gas production of 5.1 billion cubic feet per day in 2017 was up 23 percent from 2016 and 28 percent from 2015.

Refer to the “Selected Operating Data” table, on page 39, for a three-year comparison of international production volumes.

Management's Discussion and Analysis of Financial Condition and Results of Operations

U.S. Downstream



Millions of dollars	2017		2016		2015
Earnings	$	2,938	$	1,307	$	3,182

U.S. downstream operations earned $2.94 billion in 2017, compared with $1.31 billion in 2016. The increase was primarily due to a $1.16 billion benefit from U.S. tax reform, higher margins on refined product sales of $380 million, lower operating expenses of $160 million, and the absence of an asset impairment of $110 million. Partially offsetting this increase were lower gains on asset sales of $90 million and lower earnings from the 50 percent-owned Chevron Phillips Chemicals Company LLC of $70 million, primarily reflecting the impacts from Hurricane Harvey.

U.S. downstream operations earned $1.31 billion in 2016, compared with $3.18 billion in 2015. The decrease was due to lower margins on refined product sales of $1.45 billion, lower earnings from the 50 percent-owned Chevron Phillips Chemicals Company LLC of $400 million and an asset impairment of $110 million. Partially offsetting this decrease were lower operating expenses of $80 million and higher gains on asset sales of $110 million.

Refined product sales of 1.20 million barrels per day in 2017 were down 1 percent, primarily due to divestment of Hawaii refining and marketing assets in fourth quarter 2016. Sales volumes of refined products were 1.21 million barrels per day in 2016, a decrease of 1 percent from 2015, mainly reflecting lower sales of diesel. U.S. branded gasoline sales of 528,000 barrels per day in 2017 decreased 1 percent from 2016 and increased 1 percent from 2015.

Refer to the “Selected Operating Data” table on page 39 for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

International Downstream



Millions of dollars	2017			2016			2015
Earnings^*	$	2,276		$	2,128		$	4,419
^*Includes foreign currency effects:	$	(90	)	$	(25	)	$	47

International downstream earned $2.28 billion in 2017, compared with $2.13 billion in 2016. The increase in earnings was primarily due to higher gains on asset sales of $360 million, partially offset by higher operating expenses of $140 million. Foreign currency effects had an unfavorable impact on earnings of $65 million between periods.

International downstream earned $2.13 billion in 2016, compared with $4.42 billion in 2015. The decrease in earnings was primarily due to the absence of a $1.6 billion gain from the sale of the company's interest in Caltex Australia Limited in 2015, partially offset by 2016 asset sales gains of $420 million. Lower margins on refined product sales of $1.14 billion also contributed to the decline. Partially offsetting these decreases were lower operating expenses of $240 million. Foreign currency effects had an unfavorable impact on earnings of $72 million between periods.

Total refined product sales of 1.49 million barrels per day in 2017 were up 2 percent from 2016, primarily due to higher diesel and jet fuel sales. Sales of 1.46 million barrels per day in 2016 were down 3 percent from 2015. Excluding the effects of the Caltex Australia Limited divestment, refined product sales were down 1 percent, primarily reflecting lower fuel oil sales.

Refer to the “Selected Operating Data” table, on page 39, for a three-year comparison of sales volumes of gasoline and other refined products and refinery input volumes.

All Other



Millions of dollars	2017			2016			2015
Net charges^*	$	(4,169	)	$	(1,395	)	$	(1,053	)
^*Includes foreign currency effects:	$	100		$	(39	)	$	(3	)

All Other consists of worldwide cash management and debt financing activities, corporate administrative functions, insurance operations, real estate activities, and technology companies.

Net charges in 2017 increased $2.77 billion from 2016, mainly due to higher tax items, primarily reflecting a $2.47 billion expense from U.S. tax reform, higher interest expense and a reclamation related charge for a former mining asset, partially offset by lower employee expense. Foreign currency effects decreased net charges by $139 million between periods. Net

Management's Discussion and Analysis of Financial Condition and Results of Operations

charges in 2016 increased $342 million from 2015, mainly due to higher corporate charges, interest expense and corporate tax items, partially offset by lower environmental reserve additions and lower charges related to reductions in corporate staffs.

Consolidated Statement of Income

Comparative amounts for certain income statement categories are shown below:



Millions of dollars	2017		2016		2015
Sales and other operating revenues	$	134,674	$	110,215	$	129,925

Sales and other operating revenues increased in 2017 mainly due to higher refined product and crude oil prices, higher crude oil volumes, and higher natural gas volumes. The decrease between 2016 and 2015 was primarily due to lower refined product and crude oil prices, partially offset by higher crude oil volumes.



Millions of dollars	2017		2016		2015
Income from equity affiliates	$	4,438	$	2,661	$	4,684

Income from equity affiliates increased in 2017 from 2016 mainly due to higher upstream-related earnings from Tengizchevroil in Kazakhstan and Angola LNG.

Income from equity affiliates decreased in 2016 from 2015 primarily due to lower upstream-related earnings from Tengizchevroil in Kazakhstan and Petroboscan in Venezuela, and lower downstream-related earnings from CPChem and GS Caltex in South Korea.

Refer to Note 16, beginning on page 70, for a discussion of Chevron’s investments in affiliated companies.



Millions of dollars	2017		2016		2015
Other income	$	2,610	$	1,596	$	3,868

Other income of $2.6 billion in 2017 included net gains from asset sales of $2.2 billion before-tax. Other income in 2016 and 2015 included net gains from asset sales of $1.1 billion and $3.2 billion before-tax, respectively. Interest income was approximately $107 million in 2017, $145 million in 2016 and $119 million in 2015. Foreign currency effects decreased other income by $131 million in 2017, and $186 million in 2016 and increased other income $82 million in 2015.



Millions of dollars	2017		2016		2015
Purchased crude oil and products	$	75,765	$	59,321	$	69,751

Crude oil and product purchases increased $16.4 billion in 2017 primarily due to higher crude oil and refined product prices, and higher refined product and crude oil volumes. The decrease between 2016 and 2015 of $10.4 billion was primarily due to lower crude oil and refined product prices, partially offset by an increase in crude oil volumes.



Millions of dollars	2017		2016		2015
Operating, selling, general and administrative expenses	$	23,885	$	24,952	$	27,477

Operating, selling, general and administrative expenses decreased $1.1 billion between 2017 and 2016. The decrease included lower employee expenses of $690 million and non-operated joint venture expenses of $380 million.

Operating, selling, general and administrative expenses decreased $2.5 billion between 2016 and 2015. The decrease included lower employee expenses of $800 million, transportation expenses of $680 million, contract labor expenses of $370 million, materials and supplies expenses of $310 million, and fuel expenses of $310 million.



Millions of dollars	2017		2016		2015
Exploration expense	$	864	$	1,033	$	3,340

Exploration expenses in 2017 decreased from 2016 primarily due to lower charges for well write-offs.

Exploration expenses in 2016 decreased from 2015 primarily due to significantly higher 2015 charges for well write-offs largely related to project cancellations, and lower 2016 geological and geophysical expenses.

Management's Discussion and Analysis of Financial Condition and Results of Operations



Millions of dollars	2017		2016		2015
Depreciation, depletion and amortization	$	19,349	$	19,457	$	21,037

Depreciation, depletion and amortization expenses decreased in 2017 from 2016 mainly due to lower impairments and lower depreciation rates for certain oil and gas producing properties, and the absence of a 2016 impairment of a downstream asset. Partially offsetting the decrease were higher production levels, accretion and write-offs for certain oil and gas producing fields, and a reclamation related charge for a former mining asset.

The decrease in 2016 from 2015 was primarily due to lower impairments of certain oil and gas producing fields of about $3.0 billion in 2016 compared with about $3.5 billion in 2015. Also contributing to the decrease were lower production levels and accretion expenses for certain oil and gas producing fields.



Millions of dollars	2017		2016		2015
Taxes other than on income	$	12,331	$	11,668	$	12,030

Taxes other than on income increased in 2017 from 2016 primarily due to higher duties, higher crude oil, refined product and natural gas sales, and higher production. Taxes other than on income decreased in 2016 from 2015 primarily due to lower refined product and crude oil prices, and the divestment of the Pakistan fuels business at the end of June 2015.



Millions of dollars	2017			2016			2015
Income tax (benefit) expense	$	(48	)	$	(1,729	)	$	132

The decline in income tax benefit in 2017 of $1.68 billion is due to the increase in total income before tax for the company of $11.38 billion and the remeasurement impacts of U.S. tax reform. U.S. losses before tax decreased from a loss of $4.32 billion in 2016 to a loss of $441 million in 2017. This decrease in losses before tax was primarily driven by the effect of higher crude oil prices. The U.S. tax benefit increased by $650 million between year-over-year periods from $2.32 billion in 2016 to $2.97 billion in 2017. The U.S. tax benefit for 2017 included a $2.02 billion benefit from U.S. tax reform, which primarily reflected the remeasurement of U.S. deferred tax assets and liabilities, and a reduction of $1.37 billion as result of the impact of a decrease in losses before tax of $3.88 billion. International income before tax increased from $2.16 billion in 2016 to $9.66 billion in 2017. This $7.50 billion increase was primarily driven by the effect of higher crude oil prices and gains on asset sales primarily in Indonesia and Canada. The higher crude prices primarily drove the $2.34 billion increase in international income tax expense between year-over-year periods, from $588 million in 2016 to $2.93 billion in 2017. Refer also to the discussion of the effective income tax rate in Note 18 on page 75.

The decline in income tax expense in 2016 of $1.86 billion is consistent with the decline in total income before tax for the company of $7.00 billion. U.S. losses before tax increased from a loss of $2.88 billion in 2015 to a loss of $4.32 billion in 2016. This $1.44 billion increase in losses was primarily driven by the effect of lower crude oil prices. The increase in losses had a direct impact on the company’s U.S. income tax benefit, resulting in an increase of $624 million between year-over-year periods, from a tax benefit of $1.69 billion in 2015 to a tax benefit of $2.32 billion in 2016. International income before tax was reduced between calendar years from $7.72 billion in 2015 to $2.16 billion in 2016. This $5.56 billion decline was also primarily driven by the effect of lower crude oil prices. This effect drove the $1.24 billion reduction in international income tax expense between year-over-year periods, from $1.83 billion in 2015 to $588 million in 2016. Refer also to the discussion of the effective income tax rate in Note 18 on page 75.

Management's Discussion and Analysis of Financial Condition and Results of Operations

Selected Operating Data^1,2



	2017		2016		2015
U.S. Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)	519		504		501
Net Natural Gas Production (MMCFPD)³	970		1,120		1,310
Net Oil-Equivalent Production (MBOEPD)	681		691		720
Sales of Natural Gas (MMCFPD)	3,331		3,317		3,913
Sales of Natural Gas Liquids (MBPD)	30		30		26
Revenues from Net Production
Liquids ($/Bbl)	$	44.53	$	35.00	$	42.70
Natural Gas ($/MCF)	$	2.10	$	1.59	$	1.92
International Upstream
Net Crude Oil and Natural Gas Liquids Production (MBPD)⁴	1,204		1,215